Apparatus and methods for determining information from a well

ABSTRACT

A system for drilling a well may be adapted to process signals received from a fiber optic cable located in the casing of a previously drilled well or wells. The fiber optic cable may act as a distributed sensor receiving acoustic signals generated during the drilling of the well, and the system may be programmed to process the signals from the fiber optic cable to locate the borehole of the well being drilled, including its location relative to the previously drilled well or well. The system may be used to automatically update a well plan for the well being drilled responsive to information about the location of the borehole and also may be used to automatically adjust one or more drilling parameters or drilling operations responsive to the location of the second well borehole.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of priority to U.S. ProvisionalPatent Application Ser. No. 62/760,621, filed on Nov. 13, 2018, which ishereby incorporated by reference as if fully set forth herein.

BACKGROUND Description of the Invention

This application is directed to methods and systems for using fiberoptic cabling located in a first well borehole in connection withdetermining the location and shape of one or more other well boreholes,including during drilling, the relative location and/or shape of two ormore other boreholes, for planning the drilling path of a borehole, andfor identifying and determining events or conditions that occur whiledrilling.

A system and apparatus for fiber optic cabling can be used to takeadvantage of distributed sensing for locating relative positions oflateral wells, regardless of the length of the lateral well. Withtraditional surveys, error accumulation occurs due to the accumulationof sensor errors over the length of a borehole, which can be 5,000 feet,7,500 feet, 10,000 feet, 15,000 feet or longer. Positioning of lateralwells often require accuracy, such as to avoid damaging anearlier-drilled borehole. This may be especially true for pad drilling,where several wells may be drilled from a single surface pad.

As described below, the present disclosure includes systems and methodsthat use fiber optic cabling to accurately locate one or more boreholesand/or their relative positions. For example, by drilling a first wellon a pad and running fiber optic cable along its length, the shape andposition of a second well relative to the first well can be accuratelyquantified. The relative position of lateral wells is often important tomaximize production and avoid stranded hydrocarbons. The accuracy of themeasurement of the borehole location with fiber optic cable may be inthe range of inches, a significant improvement in accuracy over othermeasurement methods. In addition, the cabling fiber optic can provideuseful information to determine and identify conditions and events thatmay happen during drilling of the second or subsequent well boreholes.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding, reference is now made to thefollowing description taken in conjunction with the accompanyingdrawings in which:

FIG. 1A illustrates one embodiment of a drilling environment in which asurface steerable system may operate;

FIG. 1B illustrates one embodiment of a more detailed portion of thedrilling environment of FIG. 1A;

FIG. 1C illustrates one embodiment of a more detailed portion of thedrilling environment of FIG. 1B;

FIG. 2A illustrates one embodiment of the surface steerable system ofFIG. 1A and how information may flow to and from the system;

FIG. 2B illustrates one embodiment of a display that may be used withthe surface steerable system of FIG. 2A;

FIG. 3 illustrates one embodiment of a drilling environment that doesnot have the benefit of the surface steerable system of FIG. 2A andpossible communication channels within the environment;

FIG. 4 illustrates one embodiment of a drilling environment that has thebenefit of the surface steerable system of FIG. 2A and possiblecommunication channels within the environment;

FIG. 5 illustrates one embodiment of data flow that may be supported bythe surface steerable system of FIG. 2A;

FIG. 6 illustrates one embodiment of a method that may be executed bythe surface steerable system of FIG. 2A;

FIG. 7A illustrates a more detailed embodiment of the method of FIG. 6;

FIG. 7B illustrates a more detailed embodiment of the method of FIG. 6;

FIG. 7C illustrates one embodiment of a convergence plan diagram withmultiple convergence paths;

FIG. 8A illustrates a more detailed embodiment of a portion of themethod of FIG. 7B;

FIG. 8B illustrates a more detailed embodiment of a portion of themethod of FIG. 6;

FIG. 8C illustrates a more detailed embodiment of a portion of themethod of FIG. 6;

FIG. 8D illustrates a more detailed embodiment of a portion of themethod of FIG. 6;

FIG. 9 illustrates one embodiment of a system architecture that may beused for the surface steerable system of FIG. 2A;

FIG. 10 illustrates one embodiment of a more detailed portion of thesystem architecture of FIG. 9;

FIG. 11 illustrates one embodiment of a guidance control loop that maybe used within the system architecture of FIG. 9;

FIG. 12 illustrates one embodiment of an autonomous control loop thatmay be used within the system architecture of FIG. 9;

FIG. 13 illustrates one embodiment of a computer system that may be usedwithin the surface steerable system of FIG. 2A;

FIG. 14 illustrates the system of using fiber optic cabling to determinerelative position of lateral wells.

FIG. 15 illustrates the location of the data analytics tool at thesurface of the well.

FIGS. 16A and 16B illustrates the positioning of the fiber optic cablingrelative the casing in the well.

FIG. 17 illustrates a flow diagram of a method using a fiber optic cablein a well casing.

DETAILED DESCRIPTION

Referring now to the drawings, wherein like reference numbers are usedherein to designate like elements throughout, the various views andembodiments of a system and method for surface steerable drilling areillustrated and described, and other possible embodiments are described.The figures are not necessarily drawn to scale, and in some instancesthe drawings have been exaggerated and/or simplified in places forillustrative purposes only. One of ordinary skill in the art willappreciate the many possible applications and variations based on thefollowing examples of possible embodiments.

Referring to FIG. 1A, one embodiment of an environment 100 isillustrated with multiple wells 102, 104, 106, 108, and a drilling rig110. In the present example, the wells 102 and 104 are located in aregion 112, the well 106 is located in a region 114, the well 108 islocated in a region 116, and the drilling rig 110 is located in a region118. Each region 112, 114, 116, and 118 may represent a geographic areahaving similar geological formation characteristics. For example, region112 may include particular formation characteristics identified by rocktype, porosity, thickness, and other geological information. Theseformation characteristics affect drilling of the wells 102 and 104.Region 114 may have formation characteristics that are different enoughto be classified as a different region for drilling purposes, and thedifferent formation characteristics affect the drilling of the well 106.Likewise, formation characteristics in the regions 116 and 118 affectthe well 108 and drilling rig 110, respectively.

It is understood the regions 112, 114, 116, and 118 may vary in size andshape depending on the characteristics by which they are identified.Furthermore, the regions 112, 114, 116, and 118 may be sub-regions of alarger region. Accordingly, the criteria by which the regions 112, 114,116, and 118 are identified is less important for purposes of thepresent disclosure than the understanding that each region 112, 114,116, and 118 includes geological characteristics that can be used todistinguish each region from the other regions from a drillingperspective. Such characteristics may be relatively major (e.g., thepresence or absence of an entire rock layer in a given region) or may berelatively minor (e.g., variations in the thickness of a rock layer thatextends through multiple regions).

Accordingly, drilling a well located in the same region as other wells,such as drilling a new well in the region 112 with already existingwells 102 and 104, means the drilling process is likely to face similardrilling issues as those faced when drilling the existing wells in thesame region. For similar reasons, a drilling process performed in oneregion is likely to face issues different from a drilling processperformed in another region. However, even the drilling processes thatcreated the wells 102 and 104 may face different issues during actualdrilling as variations in the formation are likely to occur even in asingle region.

Drilling a well typically involves a substantial amount of humandecision making during the drilling process. For example, geologists anddrilling engineers use their knowledge, experience, and the availableinformation to make decisions on how to plan the drilling operation, howto accomplish the plan, and how to handle issues that arise duringdrilling. However, even the best geologists and drilling engineersperform some guesswork due to the unique nature of each borehole.Furthermore, a directional driller directly responsible for the drillingmay have drilled other boreholes in the same region and so may have somesimilar experience, but it is impossible for a human to mentally trackall the possible inputs and factor those inputs into a decision. Thiscan result in expensive mistakes, as errors in drilling can add hundredsof thousands or even millions of dollars to the drilling cost and, insome cases, drilling errors may permanently lower the output of a well,resulting in substantial long term losses.

In the present example, to aid in the drilling process, each well 102,104, 106, and 108 has corresponding collected data 120, 122, 124, and126, respectively. The collected data may include the geologicalcharacteristics of a particular formation in which the correspondingwell was formed, the attributes of a particular drilling rig, includingthe bottom hole assembly (BHA), and drilling information such asweight-on-bit (WOB), drilling speed, and/or other information pertinentto the formation of that particular borehole. The drilling informationmay be associated with a particular depth or other identifiable markerso that, for example, it is recorded that drilling of the well 102 from1000 feet to 1200 feet occurred at a first ROP through a first rocklayer with a first WOB, while drilling from 1200 feet to 1500 feetoccurred at a second ROP through a second rock layer with a second WOB.The collected data may be used to recreate the drilling process used tocreate the corresponding well 102, 104, 106, or 108 in the particularformation. It is understood that the accuracy with which the drillingprocess can be recreated depends on the level of detail and accuracy ofthe collected data.

The collected data 120, 122, 124, and 126 may be stored in a centralizeddatabase 128 as indicated by lines 130, 132, 134, and 136, respectively,which may represent any wired and/or wireless communication channel(s).The database 128 may be located at a drilling hub (not shown) orelsewhere. Alternatively, the data may be stored on a removable storagemedium that is later coupled to the database 128 in order to store thedata. The collected data 120, 122, 124, and 126 may be stored in thedatabase 128 as formation data 138, equipment data 140, and drillingdata 142 for example. Formation data 138 may include any formationinformation, such as rock type, layer thickness, layer location (e.g.,depth), porosity, gamma readings, etc. Equipment data 140 may includeany equipment information, such as drilling rig configuration (e.g.,rotary table or top drive), bit type, mud composition, etc. Drillingdata 142 may include any drilling information, such as drilling speed,WOB, differential pressure, toolface orientation, etc. The collecteddata may also be identified by well, region, and other criteria, and maybe sortable to enable the data to be searched and analyzed. It isunderstood that many different storage mechanisms may be used to storethe collected data in the database 128.

With additional reference to FIG. 1B, an environment 160 (not to scale)illustrates a more detailed embodiment of a portion of the region 118with the drilling rig 110 located at the surface 162. A drilling planhas been formulated to drill a borehole 164 extending into the ground toa true vertical depth (TVD) 166. The borehole 164 extends through stratalayers 168 and 170, stopping in layer 172, and not reaching underlyinglayers 174 and 176. The borehole 164 may be directed to a target area180 positioned in the layer 172. The target 180 may be a subsurfacepoint or points defined by coordinates or other markers that indicatewhere the borehole 164 is to end or may simply define a depth rangewithin which the borehole 164 is to remain (e.g., the layer 172 itself).It is understood that the target 180 may be any shape and size, and maybe defined in any way. Accordingly, the target 180 may represent anendpoint of the borehole 164 or may extend as far as can berealistically drilled. For example, if the drilling includes ahorizontal component and the goal is to follow the layer 172 as far aspossible, the target may simply be the layer 172 itself and drilling maycontinue until a limit is reached, such as a property boundary or aphysical limitation to the length of the drillstring. A fault 178 hasshifted a portion of each layer downwards. Accordingly, the borehole 164is located in non-shifted layer portions 168A-176A, while portions168B-176B represent the shifted layer portions.

Current drilling techniques frequently involve directional drilling toreach a target, such as the target 180. The use of directional drillinggenerally increases the amount of reserves that can be obtained and alsoincreases production rate, sometimes significantly. For example, thedirectional drilling used to provide the horizontal portion shown inFIG. 1B increases the length of the borehole in the layer 172, which isthe target layer in the present example. Directional drilling may alsobe used alter the angle of the borehole to address faults, such as thefault 178 that has shifted the layer portion 172B. Other uses fordirectional drilling include sidetracking off of an existing well toreach a different target area or a missed target area, drilling aroundabandoned drilling equipment, drilling into otherwise inaccessible ordifficult to reach locations (e.g., under populated areas or bodies ofwater), providing a relief well for an existing well, and increasing thecapacity of a well by branching off and having multiple boreholesextending in different directions or at different vertical positions forthe same well. Directional drilling is often not confined to a straighthorizontal borehole, but may involve staying within a rock layer thatvaries in depth and thickness as illustrated by the layer 172. As such,directional drilling may involve multiple vertical adjustments thatcomplicate the path of the borehole.

With additional reference to FIG. 1C, which illustrates one embodimentof a portion of the borehole 164 of FIG. 1B, the drilling of horizontalwells clearly introduces significant challenges to drilling that do notexist in vertical wells. For example, a substantially horizontal portion192 of the well may be started off of a vertical borehole 190 and onedrilling consideration is the transition from the vertical portion ofthe well to the horizontal portion. This transition is generally a curvethat defines a build up section 194 beginning at the vertical portion(called the kick off point and represented by line 196) and ending atthe horizontal portion (represented by line 198). The change ininclination per measured length drilled is typically referred to as thebuild rate and is often defined in degrees per one hundred feet drilled.For example, the build rate may be 6°/100 ft, indicating that there is asix degree change in inclination for every one hundred feet drilled. Thebuild rate for a particular build up section may remain relativelyconstant or may vary.

The build rate depends on factors such as the formation through whichthe borehole 164 is to be drilled, the trajectory of the borehole 164,the particular pipe and drill collars/BHA components used (e.g., length,diameter, flexibility, strength, mud motor bend setting, and drill bit),the mud type and flow rate, the required horizontal displacement,stabilization, and inclination. An overly aggressive built rate cancause problems such as severe doglegs (e.g., sharp changes in directionin the borehole) that may make it difficult or impossible to run casingor perform other needed tasks in the borehole 164. Depending on theseverity of the mistake, the borehole 164 may require enlarging or thebit may need to be backed out and a new passage formed. Such mistakescost time and money. However, if the built rate is too cautious,significant additional time may be added to the drilling process as itis generally slower to drill a curve than to drill straight.Furthermore, drilling a curve is more complicated and the possibility ofdrilling errors increases (e.g., overshoot and undershoot that may occurtrying to keep the bit on the planned path).

Two modes of drilling, known as rotating and sliding, are commonly usedto form the borehole 164. Rotating, also called rotary drilling, uses atopdrive or rotary table to rotate the drillstring. Rotating is usedwhen drilling is to occur along a straight path. Sliding, also calledsteering, uses a downhole mud motor with an adjustable bent housing anddoes not rotate the drillstring. Instead, sliding uses hydraulic powerto drive the downhole motor and bit. Sliding is used in order to controlwell direction.

The conventional approach to accomplish a slide can be brieflysummarized as follows. First, the rotation of the drill string isstopped. Based on feedback from measuring equipment such as a MWD tool,adjustments are made to the drill string. These adjustments continueuntil the downhole toolface that indicates the direction of the bend ofthe motor is oriented to the direction of the desired deviation of theborehole. Once the desired orientation is accomplished, pressure isapplied to the drill bit, which causes the drill bit to move in thedirection of deviation. Once sufficient distance and angle have beenbuilt, a transition back to rotating mode is accomplished by rotatingthe drill string. This rotation of the drill string neutralizes thedirectional deviation caused by the bend in the motor as it continuouslyrotates around the centerline of the borehole.

Referring again to FIG. 1A, the formulation of a drilling plan for thedrilling rig 110 may include processing and analyzing the collected datain the database 128 to create a more effective drilling plan.Furthermore, once the drilling has begun, the collected data may be usedin conjunction with current data from the drilling rig 110 to improvedrilling decisions. Accordingly, controller 144 is coupled to thedrilling rig 110 and may also be coupled to the database 128 via one ormore wired and/or wireless communication channel(s) 146. The controller144 may be on-site at the drilling rig 110 located at a remote controlcenter away from the drilling rig 110. Other inputs 148 may also beprovided to the on-site controller 144. In some embodiments, thecontroller 144 may operate as a stand-alone device with the drilling rig110. For example, the controller 144 may not be communicatively coupledto the database 128. Although shown as being positioned near or at thedrilling rig 110 in the present example, it is understood that some orall components of the controller 144 may be distributed and locatedelsewhere in other embodiments such as a remote central controlfacility.

The controller 144 may form all or part of a surface steerable system.The database 128 may also form part of the surface steerable system. Aswill be described in greater detail below, the surface steerable systemmay be used to plan and control drilling operations based on inputinformation, including feedback from the drilling process itself. Thesurface steerable system may be used to perform such operations asreceiving drilling data representing a drill path and other drillingparameters, calculating a drilling solution for the drill path based onthe received data and other available data (e.g., rig characteristics),implementing the drilling solution at the drilling rig 110, monitoringthe drilling process to gauge whether the drilling process is within adefined margin of error of the drill path, and/or calculatingcorrections for the drilling process if the drilling process is outsideof the margin of error.

Referring to FIG. 2A, a diagram 200 illustrates one embodiment ofinformation flow for a surface steerable system 201 from the perspectiveof the controller 144 of FIG. 1A. In the present example, the drillingrig 110 of FIG. 1A includes drilling equipment 216 used to perform thedrilling of a borehole, such as top drive or rotary drive equipment thatcouples to the drill string and BHA and is configured to rotate thedrill string and apply pressure to the drill bit. The drilling rig 110may include control systems such as a WOB/differential pressure controlsystem 208, a positional/rotary control system 210, and a fluidcirculation control system 212. The control systems 208, 210, and 212may be used to monitor and change drilling rig settings, such as the WOBand/or differential pressure to alter the ROP or the radial orientationof the toolface, change the flow rate of drilling mud, and perform otheroperations.

The drilling rig 110 may also include a sensor system 214 for obtainingsensor data about the drilling operation and the drilling rig 110,including the downhole equipment. For example, the sensor system 214 mayinclude measuring while drilling (MWD) and/or logging while drilling(LWD) components for obtaining information, such as toolface and/orformation logging information, that may be saved for later retrieval,transmitted with a delay or in real time using any of variouscommunication means (e.g., wireless, wireline, or mud pulse telemetry),or otherwise transferred to the controller 144. Such information mayinclude information related to hole depth, bit depth, inclination,azimuth, true vertical depth, gamma count, standpipe pressure, mud flowrate, rotary rotations per minute (RPM), bit speed, ROP, WOB, and/orother information. It is understood that all or part of the sensorsystem 214 may be incorporated into one or more of the control systems208, 210, and 212, and/or in the drilling equipment 216. As the drillingrig 110 may be configured in many different ways, it is understood thatthese control systems may be different in some embodiments, and may becombined or further divided into various subsystems.

The controller 144 receives input information 202. The input information202 may include information that is pre-loaded, received, and/or updatedin real time. The input information 202 may include a well plan,regional formation history, one or more drilling engineer parameters,MWD tool face/inclination information, LWD gamma/resistivityinformation, economic parameters, reliability parameters, and/or otherdecision guiding parameters. Some of the inputs, such as the regionalformation history, may be available from a drilling hub 216, which mayinclude the database 128 of FIG. 1A and one or more processors (notshown), while other inputs may be accessed or uploaded from othersources. For example, a web interface may be used to interact directlywith the controller 144 to upload the well plan and/or drilling engineerparameters. The input information 202 feeds into the controller 144 and,after processing by the on-site controller 144, results in controlinformation 204 that is output to the drilling rig 110 (e.g., to thecontrol systems 208, 210, and 212). The drilling rig 110 (e.g., via thesystems 208, 210, 212, and 214) provides feedback information 206 to thecontroller 144. The feedback information 206 then serves as input to thecontroller 144, enabling the controller 144 to verify that the currentcontrol information is producing the desired results or to produce newcontrol information for the drilling rig 110.

The controller 144 also provides output information 203. As will bedescribed later in greater detail, the output information 203 may bestored in the controller 144 and/or sent offsite (e.g., to the database128). The output information 203 may be used to provide updates to thedatabase 128, as well as provide alerts, request decisions, and conveyother data related to the drilling process.

Referring to FIG. 2B, one embodiment of a display 250 that may beprovided by the controller 144 is illustrated. The display 250 providesmany different types of information in an easily accessible format. Forexample, the display 250 may be a viewing screen (e.g., a monitor) thatis coupled to or forms part of the controller 144.

The display 250 provides visual indicators such as a hole depthindicator 252, a bit depth indicator 254, a GAMMA indicator 256, aninclination indicator 258, an azimuth indicator 260, and a TVD indicator262. Other indicators may also be provided, including a ROP indicator264, a mechanical specific energy (MSE) indicator 266, a differentialpressure indicator 268, a standpipe pressure indicator 270, a flow rateindicator 272, a rotary RPM indicator 274, a bit speed indicator 276,and a WOB indicator 278.

Some or all of the indicators 264, 266, 268, 270, 272, 274, 276, and/or278 may include a marker representing a target value. For purposes ofexample, markers are set as the following values, but it is understoodthat any desired target value may be representing. For example, the ROPindicator 264 may include a marker 265 indicating that the target valueis fifty ft/hr. The MSE indicator 266 may include a marker 267indicating that the target value is thirty-seven ksi. The differentialpressure indicator 268 may include a marker 269 indicating that thetarget value is two hundred psi. The ROP indicator 264 may include amarker 265 indicating that the target value is fifty ft/hr. Thestandpipe pressure indicator 270 may have no marker in the presentexample. The flow rate indicator 272 may include a marker 273 indicatingthat the target value is five hundred gpm. The rotary RPM indicator 274may include a marker 275 indicating that the target value is zero RPM(due to sliding). The bit speed indicator 276 may include a marker 277indicating that the target value is one hundred and fifty RPM. The WOBindicator 278 may include a marker 279 indicating that the target valueis ten klbs. Although only labeled with respect to the indicator 264,each indicator may include a colored band or another marking toindicate, for example, whether the respective gauge value is within asafe range (e.g., indicated by a green color), within a caution range(e.g., indicated by a yellow color), or within a danger range (e.g.,indicated by a red color). Although not shown, in some embodiments,multiple markers may be present on a single indicator. The markers mayvary in color and/or size.

A log chart 280 may visually indicate depth versus one or moremeasurements (e.g., may represent log inputs relative to a progressingdepth chart). For example, the log chart 280 may have a y-axisrepresenting depth and an x-axis representing a measurement such asGAMMA count 281 (as shown), ROP 283 (e.g., empirical ROP and normalizedROP), or resistivity. An autopilot button 282 and an oscillate button284 may be used to control activity. For example, the autopilot button282 may be used to engage or disengage an autopilot, while the oscillatebutton 284 may be used to directly control oscillation of the drillstring or engage/disengage an external hardware device or controller viasoftware and/or hardware.

A circular chart 286 may provide current and historical toolfaceorientation information (e.g., which way the bend is pointed). Forpurposes of illustration, the circular chart 286 represents threehundred and sixty degrees. A series of circles within the circular chart286 may represent a timeline of toolface orientations, with the sizes ofthe circles indicating the temporal position of each circle. Forexample, larger circles may be more recent than smaller circles, so thelargest circle 288 may be the newest reading and the smallest circle 286may be the oldest reading. In other embodiments, the circles mayrepresent the energy and/or progress made via size, color, shape, anumber within a circle, etc. For example, the size of a particularcircle may represent an accumulation of orientation and progress for theperiod of time represented by the circle. In other embodiments,concentric circles representing time (e.g., with the outside of thecircular chart 286 being the most recent time and the center point beingthe oldest time) may be used to indicate the energy and/or progress(e.g., via color and/or patterning such as dashes or dots rather than asolid line).

The circular chart 286 may also be color coded, with the color codingexisting in a band 290 around the circular chart 286 or positioned orrepresented in other ways. The color coding may use colors to indicateactivity in a certain direction. For example, the color red may indicatethe highest level of activity, while the color blue may indicate thelowest level of activity. Furthermore, the arc range in degrees of acolor may indicate the amount of deviation. Accordingly, a relativelynarrow (e.g., thirty degrees) arc of red with a relatively broad (e.g.,three hundred degrees) arc of blue may indicate that most activity isoccurring in a particular toolface orientation with little deviation.For purposes of illustration, the color blue extends from approximately22-337 degrees, the color green extends from approximately 15-22 degreesand 337-345 degrees, the color yellow extends a few degrees around the13 and 345 degree marks, and the color red extends from approximately347-10 degrees. Transition colors or shades may be used with, forexample, the color orange marking the transition between red and yellowand/or a light blue marking the transition between blue and green.

This color coding enables the display 250 to provide an intuitivesummary of how narrow the standard deviation is and how much of theenergy intensity is being expended in the proper direction. Furthermore,the center of energy may be viewed relative to the target. For example,the display 250 may clearly show that the target is at ninety degreesbut the center of energy is at forty-five degrees.

Other indicators may be present, such as a slide indicator 292 toindicate how much time remains until a slide occurs and/or how much timeremains for a current slide. For example, the slide indicator mayrepresent a time, a percentage (e.g., current slide is fifty-six percentcomplete), a distance completed, and/or a distance remaining. The slideindicator 292 may graphically display information using, for example, acolored bar 293 that increases or decreases with the slide's progress.In some embodiments, the slide indicator may be built into the circularchart 286 (e.g., around the outer edge with an increasing/decreasingband), while in other embodiments the slide indicator may be a separateindicator such as a meter, a bar, a gauge, or another indicator type.

An error indicator 294 may be present to indicate a magnitude and/or adirection of error. For example, the error indicator 294 may indicatethat the estimated drill bit position is a certain distance from theplanned path, with a location of the error indicator 294 around thecircular chart 286 representing the heading. For example, FIG. 2Billustrates an error magnitude of fifteen feet and an error direction offifteen degrees. The error indicator 294 may be any color but is red forpurposes of example. It is understood that the error indicator 294 maypresent a zero if there is no error and/or may represent that the bit ison the path in other ways, such as being a green color. Transitioncolors, such as yellow, may be used to indicate varying amounts oferror. In some embodiments, the error indicator 294 may not appearunless there is an error in magnitude and/or direction. A marker 296 mayindicate an ideal slide direction. Although not shown, other indicatorsmay be present, such as a bit life indicator to indicate an estimatedlifetime for the current bit based on a value such as time and/ordistance.

It is understood that the display 250 may be arranged in many differentways. For example, colors may be used to indicate normal operation,warnings, and problems. In such cases, the numerical indicators maydisplay numbers in one color (e.g., green) for normal operation, may useanother color (e.g., yellow) for warnings, and may use yet another color(e.g., red) if a serious problem occurs. The indicators may also flashor otherwise indicate an alert. The gauge indicators may include colors(e.g., green, yellow, and red) to indicate operational conditions andmay also indicate the target value (e.g., an ROP of 100 ft/hr). Forexample, the ROP indicator 268 may have a green bar to indicate a normallevel of operation (e.g., from 10-300 ft/hr), a yellow bar to indicate awarning level of operation (e.g., from 300-360 ft/hr), and a red bar toindicate a dangerous or otherwise out of parameter level of operation(e.g., from 360-390 ft/hr). The ROP indicator 268 may also display amarker at 100 ft/hr to indicate the desired target ROP.

Furthermore, the use of numeric indicators, gauges, and similar visualdisplay indicators may be varied based on factors such as theinformation to be conveyed and the personal preference of the viewer.Accordingly, the display 250 may provide a customizable view of variousdrilling processes and information for a particular individual involvedin the drilling process. For example, the surface steerable system 201may enable a user to customize the display 250 as desired, althoughcertain features (e.g., standpipe pressure) may be locked to preventremoval. This locking may prevent a user from intentionally oraccidentally removing important drilling information from the display.Other features may be set by preference. Accordingly, the level ofcustomization and the information shown by the display 250 may becontrolled based on who is viewing the display and their role in thedrilling process.

Referring again to FIG. 2A, it is understood that the level ofintegration between the controller 144 and the drilling rig 110 maydepend on such factors as the configuration of the drilling rig 110 andwhether the controller 144 is able to fully support that configuration.One or more of the control systems 208, 210, and 212 may be part of thecontroller 144, may be third-party systems, and/or may be part of thedrilling rig 110. For example, an older drilling rig 110 may haverelatively few interfaces with which the controller 144 is able tointeract. For purposes of illustration, if a knob must be physicallyturned to adjust the WOB on the drilling rig 110, the controller 144will not be able to directly manipulate the knob without a mechanicalactuator. If such an actuator is not present, the controller 144 mayoutput the setting for the knob to a screen, and an operator may thenturn the knob based on the setting. Alternatively, the controller 144may be directly coupled to the knob's electrical wiring.

However, a newer or more sophisticated drilling rig 110, such as a rigthat has electronic control systems, may have interfaces with which thecontroller 144 can interact for direct control. For example, anelectronic control system may have a defined interface and thecontroller 144 may be configured to interact with that definedinterface. It is understood that, in some embodiments, direct controlmay not be allowed even if possible. For example, the controller 144 maybe configured to display the setting on a screen for approval, and maythen send the setting to the appropriate control system only when thesetting has been approved.

Referring to FIG. 3, one embodiment of an environment 300 illustratesmultiple communication channels (indicated by arrows) that are commonlyused in existing directional drilling operations that do not have thebenefit of the surface steerable system 201 of FIG. 2A. Thecommunication channels couple various individuals involved in thedrilling process. The communication channels may support telephonecalls, emails, text messages, faxes, data transfers (e.g., filetransfers over networks), and other types of communications.

The individuals involved in the drilling process may include a drillingengineer 302, a geologist 304, a directional driller 306, a tool pusher308, a driller 310, and a rig floor crew 312. One or more companyrepresentatives (e.g., company men) 314 may also be involved. Theindividuals may be employed by different organizations, which canfurther complicate the communication process. For example, the drillingengineer 302, geologist 304, and company man 314 may work for anoperator, the directional driller 306 may work for a directionaldrilling service provider, and the tool pusher 308, driller 310, and rigfloor crew 312 may work for a rig service provider.

The drilling engineer 302 and geologist 304 are often located at alocation remote from the drilling rig (e.g., in a home office/drillinghub). The drilling engineer 302 may develop a well plan 318 and may makedrilling decisions based on drilling rig information. The geologist 304may perform such tasks as formation analysis based on seismic, gamma,and other data. The directional driller 306 is generally located at thedrilling rig and provides instructions to the driller 310 based on thecurrent well plan and feedback from the drilling engineer 302. Thedriller 310 handles the actual drilling operations and may rely on therig floor crew 312 for certain tasks. The tool pusher 308 may be incharge of managing the entire drilling rig and its operation.

The following is one possible example of a communication process withinthe environment 300, although it is understood that many communicationprocesses may be used. The use of a particular communication process maydepend on such factors as the level of control maintained by variousgroups within the process, how strictly communication channels areenforced, and similar factors. In the present example, the directionaldriller 306 uses the well plan 318 to provide drilling instructions tothe driller 310. The driller 310 controls the drilling using controlsystems such as the control systems 208, 210, and 212 of FIG. 2A. Duringdrilling, information from sensor equipment such as downhole MWDequipment 316 and/or rig sensors 320 may indicate that a formation layerhas been reached twenty feet higher than expected by the geologist 304.This information is passed back to the drilling engineer 302 and/orgeologist 304 through the company man 314, and may pass through thedirectional driller 306 before reaching the company man 314.

The drilling engineer 302/well planner (not shown), either alone or inconjunction with the geologist 306, may modify the well plan 318 or makeother decisions based on the received information. The modified wellplan and/or other decisions may or may not be passed through the companyman 314 to the directional driller 306, who then tells the driller 310how to drill. The driller 310 may modify equipment settings (e.g.,toolface orientation) and, if needed, pass orders on to the rig floorcrew 312. For example, a change in WOB may be performed by the driller310 changing a setting, while a bit trip may require the involvement ofthe rig floor crew 312. Accordingly, the level of involvement ofdifferent individuals may vary depending on the nature of the decisionto be made and the task to be performed. The proceeding example may bemore complex than described. Multiple intermediate individuals may beinvolved and, depending on the communication chain, some instructionsmay be passed through the tool pusher 308.

The environment 300 presents many opportunities for communicationbreakdowns as information is passed through the various communicationchannels, particularly given the varying types of communication that maybe used. For example, verbal communications via phone may bemisunderstood and, unless recorded, provide no record of what was said.Furthermore, accountability may be difficult or impossible to enforce assomeone may provide an authorization but deny it or claim that theymeant something else. Without a record of the information passingthrough the various channels and the authorizations used to approvechanges in the drilling process, communication breakdowns can bedifficult to trace and address. As many of the communication channelsillustrated in FIG. 3 pass information through an individual to otherindividuals (e.g., an individual may serve as an information conduitbetween two or more other individuals), the risk of breakdown increasesdue to the possibility that errors may be introduced in the information.

Even if everyone involved does their part, drilling mistakes may beamplified while waiting for an answer. For example, a message may besent to the geologist 306 that a formation layer seems to be higher thanexpected, but the geologist 306 may be asleep. Drilling may continuewhile waiting for the geologist 306 and the continued drilling mayamplify the error. Such errors can cost hundreds of thousands ormillions of dollars. However, the environment 300 provides no way todetermine if the geologist 304 has received the message and no way toeasily notify the geologist 304 or to contact someone else when there isno response within a defined period of time. Even if alternate contactsare available, such communications may be cumbersome and there may bedifficulty in providing all the information that the alternate wouldneed for a decision.

Referring to FIG. 4, one embodiment of an environment 400 illustratescommunication channels that may exist in a directional drillingoperation having the benefit of the surface steerable system 201 of FIG.2A. In the present example, the surface steerable system 201 includesthe drilling hub 216, which includes the regional database 128 of FIG.1A and processing unit(s) 404 (e.g., computers). The drilling hub 216also includes communication interfaces (e.g., web portals) 406 that maybe accessed by computing devices capable of wireless and/or wirelinecommunications, including desktop computers, laptops, tablets, smartphones, and personal digital assistants (PDAs). The controller 144includes one or more local databases 410 (where “local” is from theperspective of the controller 144) and processing unit(s) 412.

The drilling hub 216 is remote from the controller 144, and variousindividuals associated with the drilling operation interact eitherthrough the drilling hub 216 or through the controller 144. In someembodiments, an individual may access the drilling project through boththe drilling hub 216 and controller 144. For example, the directionaldriller 306 may use the drilling hub 216 when not at the drilling siteor the controller 144 is remotely located and may use the controller 144when at the drilling site when the controller 144 is located on-site.

The drilling engineer 302 and geologist 304 may access the surfacesteerable system 201 remotely via the portal 406 and set variousparameters such as rig limit controls. Other actions may also besupported, such as granting approval to a request by the directionaldriller 306 to deviate from the well plan and evaluating the performanceof the drilling operation. The directional driller 306 may be locatedeither at the drilling rig 110 or off-site. Being off-site (e.g., at thedrilling hub 216, remotely located controller or elsewhere) enables asingle directional driller to monitor multiple drilling rigs. Whenoff-site, the directional driller 306 may access the surface steerablesystem 201 via the portal 406. When on-site, the directional driller 306may access the surface steerable system via the controller 144.

The driller 310 may get instructions via the controller 144, therebylessening the possibly of miscommunication and ensuring that theinstructions were received. Although the tool pusher 308, rig floor crew312, and company man 314 are shown communicating via the driller 310, itis understood that they may also have access to the controller 144.Other individuals, such as a MWD hand 408, may access the surfacesteerable system 201 via the drilling hub 216, the controller 144,and/or an individual such as the driller 310.

As illustrated in FIG. 4, many of the individuals involved in a drillingoperation may interact through the surface steerable system 201. Thisenables information to be tracked as it is handled by the variousindividuals involved in a particular decision. For example, the surfacesteerable system 201 may track which individual submitted information(or whether information was submitted automatically), who viewed theinformation, who made decisions, when such events occurred, and similarinformation-based issues. This provides a complete record of howparticular information propagated through the surface steerable system201 and resulted in a particular drilling decision. This also providesrevision tracking as changes in the well plan occur, which in turnenables entire decision chains to be reviewed. Such reviews may lead toimproved decision making processes and more efficient responses toproblems as they occur.

In some embodiments, documentation produced using the surface steerablesystem 201 may be synchronized and/or merged with other documentation,such as that produced by third party systems such as the WellViewproduct produced by Peloton Computer Enterprises Ltd. of Calgary,Canada. In such embodiments, the documents, database files, and otherinformation produced by the surface steerable system 201 is synchronizedto avoid such issues as redundancy, mismatched file versions, and othercomplications that may occur in projects where large numbers ofdocuments are produced, edited, and transmitted by a relatively largenumber of people.

The surface steerable system 201 may also impose mandatory informationformats and other constraints to ensure that predefined criteria aremet. For example, an electronic form provided by the surface steerablesystem 201 in response to a request for authorization may require thatsome fields are filled out prior to submission. This ensures that thedecision maker has the relevant information prior to making thedecision. If the information for a required field is not available, thesurface steerable system 201 may require an explanation to be enteredfor why the information is not available (e.g., sensor failure).Accordingly, a level of uniformity may be imposed by the surfacesteerable system 201, while exceptions may be defined to enable thesurface steerable system 201 to handle various scenarios.

The surface steerable system 201 may also send alerts (e.g., email ortext alerts) to notify one or more individuals of a particular problem,and the recipient list may be customized based on the problem.Furthermore, contact information may be time-based, so the surfacesteerable system 201 may know when a particular individual is available.In such situations, the surface steerable system 201 may automaticallyattempt to communicate with an available contact rather than waiting fora response from a contact that is likely not available.

As described previously, the surface steerable system 201 may present acustomizable display of various drilling processes and information for aparticular individual involved in the drilling process. For example, thedrilling engineer 302 may see a display that presents informationrelevant to the drilling engineer's tasks, and the geologist 304 may seea different display that includes additional and/or more detailedformation information. This customization enables each individual toreceive information needed for their particular role in the drillingprocess while minimizing or eliminating unnecessary information.

Referring to FIG. 5, one embodiment of an environment 500 illustratesdata flow that may be supported by the surface steerable system 201 ofFIG. 2A. The data flow 500 begins at block 502 and may move through twobranches, although some blocks in a branch may not occur before otherblocks in the other branch. One branch involves the drilling hub 216 andthe other branch involves the controller 144 at the drilling rig 110.

In block 504, a geological survey is performed. The survey results arereviewed by the geologist 304 and a formation report 506 is produced.The formation report 506 details formation layers, rock type, layerthickness, layer depth, and similar information that may be used todevelop a well plan. In block 508, a well plan is developed by a wellplanner 524 and/or the drilling engineer 302 based on the formationreport and information from the regional database 128 at the drillinghub 216. Block 508 may include selection of a BHA and the setting ofcontrol limits. The well plan is stored in the database 128. Thedrilling engineer 302 may also set drilling operation parameters in step510 that are also stored in the database 128.

In the other branch, the drilling rig 110 is constructed in block 512.At this point, as illustrated by block 526, the well plan, BHAinformation, control limits, historical drilling data, and controlcommands may be sent from the database 128 to the local database 410.Using the receiving information, the directional driller 306 inputsactual BHA parameters in block 514. The company man 314 and/or thedirectional driller 306 may verify performance control limits in block516, and the control limits are stored in the local database 410 of thecontroller 144. The performance control limits may include multiplelevels such as a warning level and a critical level corresponding to noaction taken within feet/minutes.

Once drilling begins, a diagnostic logger (described later in greaterdetail) 520 that is part of the controller 144 logs information relatedto the drilling such as sensor information and maneuvers and stores theinformation in the local database 410 in block 526. The information issent to the database 128. Alerts are also sent from the controller 144to the drilling hub 216. When an alert is received by the drilling hub216, an alert notification 522 is sent to defined individuals, such asthe drilling engineer 302, geologist 304, and company man 314. Theactual recipient may vary based on the content of the alert message orother criteria. The alert notification 522 may result in the well planand the BHA information and control limits being modified in block 508and parameters being modified in block 510. These modifications aresaved to the database 128 and transferred to the local database 410. TheBHA may be modified by the directional driller 306 in block 518, and thechanges propagated through blocks 514 and 516 with possible updatedcontrol limits. Accordingly, the surface steerable system 201 mayprovide a more controlled flow of information than may occur in anenvironment without such a system.

The flow charts described herein illustrate various exemplary functionsand operations that may occur within various environments. Accordingly,these flow charts are not exhaustive and that various steps may beexcluded to clarify the aspect being described. For example, it isunderstood that some actions, such as network authentication processes,notifications, and handshakes, may have been performed prior to thefirst step of a flow chart. Such actions may depend on the particulartype and configuration of communications engaged in by the controller144 and/or drilling hub 216. Furthermore, other communication actionsmay occur between illustrated steps or simultaneously with illustratedsteps.

The surface steerable system 201 includes large amounts of dataspecifically related to various drilling operations as stored indatabases such as the databases 128 and 410. As described with respectto FIG. 1A, this data may include data collected from many differentlocations and may correspond to many different drilling operations. Thedata stored in the database 128 and other databases may be used for avariety of purposes, including data mining and analytics, which may aidin such processes as equipment comparisons, drilling plan formulation,convergence planning, recalibration forecasting, and self-tuning (e.g.,drilling performance optimization). Some processes, such as equipmentcomparisons, may not be performed in real time using incoming data,while others, such as self-tuning, may be performed in real time or nearreal time. Accordingly, some processes may be executed at the drillinghub 216, other processes may be executed at the controller 144, andstill other processes may be executed by both the drilling hub 216 andthe controller 144 with communications occurring before, during, and/orafter the processes are executed. As described below in variousexamples, some processes may be triggered by events (e.g., recalibrationforecasting) while others may be ongoing (e.g., self-tuning).

For example, in equipment comparison, data from different drillingoperations (e.g., from drilling the wells 102, 104, 106, and 108) may benormalized and used to compare equipment wear, performance, and similarfactors. For example, the same bit may have been used to drill the wells102 and 106, but the drilling may have been accomplished using differentparameters (e.g., rotation speed and WOB). By normalizing the data, thetwo bits can be compared more effectively. The normalized data may befurther processed to improve drilling efficiency by identifying whichbits are most effective for particular rock layers, which drillingparameters resulted in the best ROP for a particular formation, ROPversus reliability tradeoffs for various bits in various rock layers,and similar factors. Such comparisons may be used to select a bit foranother drilling operation based on formation characteristics or othercriteria. Accordingly, by mining and analyzing the data available viathe surface steerable system 201, an optimal equipment profile may bedeveloped for different drilling operations. The equipment profile maythen be used when planning future wells or to increase the efficiency ofa well currently being drilled. This type of drilling optimization maybecome increasingly accurate as more data is compiled and analyzed.

In drilling plan formulation, the data available via the surfacesteerable system 201 may be used to identify likely formationcharacteristics and to select an appropriate equipment profile. Forexample, the geologist 304 may use local data obtained from the plannedlocation of the drilling rig 110 in conjunction with regional data fromthe database 128 to identify likely locations of the layers 168A-176A(FIG. 1B). Based on that information, the drilling engineer 302 cancreate a well plan that will include the build curve of FIG. 1C.

Referring to FIG. 6, a method 600 illustrates one embodiment of anevent-based process that may be executed by the controller 144 of FIG.2A. For example, software instructions needed to execute the method 600may be stored on a computer readable storage medium of the on-sitecontroller 144 and then executed by the processor 412 that is coupled tothe storage medium and is also part of the on-site controller 144.

In step 602, the on-site controller 144 receives inputs, such as aplanned path for a borehole, formation information for the borehole,equipment information for the drilling rig, and a set of costparameters. The cost parameters may be used to guide decisions made bythe controller 144 as will be explained in greater detail below. Theinputs may be received in many different ways, including receivingdocument (e.g., spreadsheet) uploads, accessing a database (e.g., thedatabase 128 of FIG. 1A), and/or receiving manually entered data.

In step 604, the planned path, the formation information, the equipmentinformation, and the set of cost parameters are processed to producecontrol parameters (e.g., the control information 204 of FIG. 2A) forthe drilling rig 110. The control parameters may define the settings forvarious drilling operations that are to be executed by the drilling rig110 to form the borehole, such as WOB, flow rate of mud, toolfaceorientation, and similar settings. In some embodiments, the controlparameters may also define particular equipment selections, such as aparticular bit. In the present example, step 604 is directed to defininginitial control parameters for the drilling rig 110 prior to thebeginning of drilling, but it is understood that step 604 may be used todefine control parameters for the drilling rig 110 even after drillinghas begun. For example, the controller 144 may be put in place prior todrilling or may be put in place after drilling has commenced, in whichcase the method 600 may also receive current borehole information instep 602.

In step 606, the control parameters are output for use by the drillingrig 110. In embodiments where the controller 144 is directly coupled tothe drilling rig 110, outputting the control parameters may includesending the control parameters directly to one or more of the controlsystems of the drilling rig 110 (e.g., the control systems 210, 212, and214). In other embodiments, outputting the control parameters mayinclude displaying the control parameters on a screen, printing thecontrol parameters, and/or copying them to a storage medium (e.g., aUniversal Serial Bus (USB) drive) to be transferred manually.

In step 608, feedback information received from the drilling rig 110(e.g., from one or more of the control systems 210, 212, and 214 and/orsensor system 216) is processed. The feedback information may providethe on-site controller 144 with the current state of the borehole (e.g.,depth and inclination), the drilling rig equipment, and the drillingprocess, including an estimated position of the bit in the borehole. Theprocessing may include extracting desired data from the feedbackinformation, normalizing the data, comparing the data to desired orideal parameters, determining whether the data is within a definedmargin of error, and/or any other processing steps needed to make use ofthe feedback information.

In step 610, the controller 144 may take action based on the occurrenceof one or more defined events. For example, an event may trigger adecision on how to proceed with drilling in the most cost effectivemanner. Events may be triggered by equipment malfunctions, pathdifferences between the measured borehole and the planned borehole,upcoming maintenance periods, unexpected geological readings, and anyother activity or non-activity that may affect drilling the borehole. Itis understood that events may also be defined for occurrences that havea less direct impact on drilling, such as actual or predicted laborshortages, actual or potential licensing issues for mineral rights,actual or predicted political issues that may impact drilling, andsimilar actual or predicted occurrences. Step 610 may also result in noaction being taken if, for example, drilling is occurring without anyissues and the current control parameters are satisfactory.

An event may be defined in the received inputs of step 602 or definedlater. Events may also be defined on site using the controller 144. Forexample, if the drilling rig 110 has a particular mechanical issue, oneor more events may be defined to monitor that issue in more detail thanmight ordinarily occur. In some embodiments, an event chain may beimplemented where the occurrence of one event triggers the monitoring ofanother related event. For example, a first event may trigger anotification about a potential problem with a piece of equipment and mayalso activate monitoring of a second event. In addition to activatingthe monitoring of the second event, the triggering of the first eventmay result in the activation of additional oversight that involves, forexample, checking the piece of equipment more frequently or at a higherlevel of detail. If the second event occurs, the equipment may be shutdown and an alarm sounded, or other actions may be taken. This enablesdifferent levels of monitoring and different levels of responses to beassigned independently if needed.

Referring to FIG. 7A, a method 700 illustrates a more detailedembodiment of the method 600 of FIG. 6, particularly of step 610. Assteps 702, 704, 706, and 708 are similar or identical to steps 602, 604,606, and 608, respectively, of FIG. 6, they are not described in detailin the present embodiment. In the present example, the action of step610 of FIG. 6 is based on whether an event has occurred and the actionneeded if the event has occurred.

Accordingly, in step 710, a determination is made as to whether an eventhas occurred based on the inputs of steps 702 and 708. If no event hasoccurred, the method 700 returns to step 708. If an event has occurred,the method 700 moves to step 712, where calculations are performed basedon the information relating to the event and at least one costparameter. It is understood that additional information may be obtainedand/or processed prior to or as part of step 712 if needed. For example,certain information may be used to determine whether an event hasoccurred, and additional information may then be retrieved and processedto determine the particulars of the event.

In step 714, new control parameters may be produced based on thecalculations of step 712. In step 716, a determination may be made as towhether changes are needed in the current control parameters. Forexample, the calculations of step 712 may result in a decision that thecurrent control parameters are satisfactory (e.g., the event may notaffect the control parameters). If no changes are needed, the method 700returns to step 708. If changes are needed, the controller 144 outputsthe new parameters in step 718. The method 700 may then return to step708. In some embodiments, the determination of step 716 may occur beforestep 714. In such embodiments, step 714 may not be executed if thecurrent control parameters are satisfactory.

In a more detailed example of the method 700, assume that the controller144 is involved in drilling a borehole and that approximately sixhundred feet remain to be drilled. An event has been defined that warnsthe controller 144 when the drill bit is predicted to reach a minimumlevel of efficiency due to wear and this event is triggered in step 710at the six hundred foot mark. The event may be triggered because thedrill bit is within a certain number of revolutions before reaching theminimum level of efficiency, within a certain distance remaining (basedon strata type, thickness, etc.) that can be drilled before reaching theminimum level of efficiency, or may be based on some other factor orfactors. Although the event of the current example is triggered prior tothe predicted minimum level of efficiency being reached in order toproactively schedule drilling changes if needed, it is understood thatthe event may be triggered when the minimum level is actually reached.

The controller 144 may perform calculations in step 712 that account forvarious factors that may be analyzed to determine how the last sixhundred feet is drilled. These factors may include the rock type andthickness of the remaining six hundred feet, the predicted wear of thedrill bit based on similar drilling conditions, location of the bit(e.g., depth), how long it will take to change the bit, and a costversus time analysis. Generally, faster drilling is more cost effective,but there are many tradeoffs. For example, increasing the WOB ordifferential pressure to increase the rate of penetration may reduce thetime it takes to finish the borehole, but may also wear out the drillbit faster, which will decrease the drilling effectiveness and slow thedrilling down. If this slowdown occurs too early, it may be lessefficient than drilling more slowly. Therefore, there is a tradeoff thatmust be calculated. Too much WOB or differential pressure may also causeother problems, such as damaging downhole tools. Should one of theseproblems occur, taking the time to trip the bit or drill a sidetrack mayresult in more total time to finish the borehole than simply drillingmore slowly, so faster may not be better. The tradeoffs may berelatively complex, with many factors to be considered.

In step 714, the controller 144 produces new control parameters based onthe solution calculated in step 712. In step 716, a determination ismade as to whether the current parameters should be replaced by the newparameters. For example, the new parameters may be compared to thecurrent parameters. If the two sets of parameters are substantiallysimilar (e.g., as calculated based on a percentage change or margin oferror of the current path with a path that would be created using thenew control parameters) or identical to the current parameters, nochanges would be needed. However, if the new control parameters call forchanges greater than the tolerated percentage change or outside of themargin of error, they are output in step 718. For example, the newcontrol parameters may increase the WOB and also include the rate of mudflow significantly enough to override the previous control parameters.In other embodiments, the new control parameters may be outputregardless of any differences, in which case step 716 may be omitted. Instill other embodiments, the current path and the predicted path may becompared before the new parameters are produced, in which case step 714may occur after step 716.

Referring to FIG. 7B and with additional reference to FIG. 7C, a method720 (FIG. 7B) and diagram 740 (FIG. 7C) illustrate a more detailedembodiment of the method 600 of FIG. 6, particularly of step 610. Assteps 722, 724, 726, and 728 are similar or identical to steps 602, 604,606, and 608, respectively, of FIG. 6, they are not described in detailin the present embodiment. In the present example, the action of step610 of FIG. 6 is based on whether the drilling has deviated from theplanned path.

In step 730, a comparison may be made to compare the estimated bitposition and trajectory with a desired point (e.g., a desired bitposition) along the planned path. The estimated bit position may becalculated based on information such as a survey reference point and/orrepresented as an output calculated by a borehole estimator (as will bedescribed later) and may include a bit projection path and/or point thatrepresents a predicted position of the bit if it continues its currenttrajectory from the estimated bit position. Such information may beincluded in the inputs of step 722 and feedback information of step 728or may be obtained in other ways. It is understood that the estimatedbit position and trajectory may not be calculated exactly, but mayrepresent an estimate the current location of the drill bit based on thefeedback information. As illustrated in FIG. 7C, the estimated bitposition is indicated by arrow 743 relative to the desired bit position741 along the planned path 742.

In step 732, a determination may be made as to whether the estimated bitposition 743 is within a defined margin of error of the desired bitposition. If the estimated bit position is within the margin of error,the method 720 returns to step 728. If the estimated bit position is notwithin the margin of error, the on-site controller 144 calculates aconvergence plan in step 734. With reference to FIG. 7C, for purposes ofthe present example, the estimated bit position 743 is outside of themargin of error.

In some embodiments, a projected bit position (not shown) may also beused. For example, the estimated bit position 743 may be extended viacalculations to determine where the bit is projected to be after acertain amount of drilling (e.g., time and/or distance). Thisinformation may be used in several ways. If the estimated bit position743 is outside the margin of error, the projected bit position 743 mayindicate that the current bit path will bring the bit within the marginof error without any action being taken. In such a scenario, action maybe taken only if it will take too long to reach the projected bitposition when a more optimal path is available. If the estimated bitposition is inside the margin of error, the projected bit position maybe used to determine if the current path is directing the bit away fromthe planned path. In other words, the projected bit position may be usedto proactively detect that the bit is off course before the margin oferror is reached. In such a scenario, action may be taken to correct thecurrent path before the margin of error is reached.

The convergence plan identifies a plan by which the bit can be movedfrom the estimated bit position 743 to the planned path 742. It is notedthat the convergence plan may bypass the desired bit position 741entirely, as the objective is to get the actual drilling path back tothe planned path 742 in the most optimal manner. The most optimal mannermay be defined by cost, which may represent a financial value, areliability value, a time value, and/or other values that may be definedfor a convergence path.

As illustrated in FIG. 7C, an infinite number of paths may be selectedto return the bit to the planned path 742. The paths may begin at theestimated bit position 743 or may begin at other points along aprojected path 752 that may be determined by calculating future bitpositions based on the current trajectory of the bit from the estimatedbit position 752. In the present example, a first path 744 results inlocating the bit at a position 745 (e.g., a convergence point). Theconvergence point 745 is outside of a lower limit 753 defined by a mostaggressive possible correction (e.g., a lower limit on a window ofcorrection). This correction represents the most aggressive possibleconvergence path, which may be limited by such factors as a maximumdirectional change possible in the convergence path, where any greaterdirectional change creates a dogleg that makes it difficult orimpossible to run casing or perform other needed tasks. A second path746 results in a convergence point 747, which is right at the lowerlimit 753. A third path 748 results in a convergence point 749, whichrepresents a mid-range convergence point. A third path 750 results in aconvergence point 751, which occurs at an upper limit 754 defined by amaximum convergence delay (e.g., an upper limit on the window ofcorrection).

A fourth path 756 may begin at a projected point or bit position 755that lies along the projected path 752 and result in a convergence point757, which represents a mid-range convergence point. The path 756 may beused by, for example, delaying a trajectory change until the bit reachesthe position 755. Many additional convergence options may be opened upby using projected points for the basis of convergence plans as well asthe estimated bit position.

A fifth path 758 may begin at a projected point or bit position 760 thatlies along the projected path 750 and result in a convergence point 759.In such an embodiment, different convergence paths may include similaror identical path segments, such as the similar or identical path sharedby the convergence points 751 and 759 to the point 760. For example, thepoint 760 may mark a position on the path 750 where a slide segmentbegins (or continues from a previous slide segment) for the path 758 anda straight line path segment begins (or continues) for the path 750. Thesurface steerable system 144 may calculate the paths 750 and 758 as twoentirely separate paths or may calculate one of the paths as deviatingfrom (e.g., being a child of) the other path. Accordingly, any path mayhave multiple paths deviating from that path based on, for example,different slide points and slide times.

Each of these paths 744, 746, 748, 750, 756, and 758 may presentadvantages and disadvantages from a drilling standpoint. For example,one path may be longer and may require more sliding in a relatively softrock layer, while another path may be shorter but may require moresliding through a much harder rock layer. Accordingly, tradeoffs may beevaluated when selecting one of the convergence plans rather than simplyselecting the most direct path for convergence. The tradeoffs may, forexample, consider a balance between ROP, total cost, dogleg severity,and reliability. While the number of convergence plans may vary, theremay be hundreds or thousands of convergence plans in some embodimentsand the tradeoffs may be used to select one of those hundreds orthousands for implementation. The convergence plans from which the finalconvergence plan is selected may include plans calculated from theestimated bit position 743 as well as plans calculated from one or moreprojected points along the projected path.

In some embodiments, straight line projections of the convergence pointvectors, after correction to the well plan 742, may be evaluated topredict the time and/or distance to the next correction requirement.This evaluation may be used when selecting the lowest total cost optionby avoiding multiple corrections where a single more forward thinkingoption might be optimal. As an example, one of the solutions provided bythe convergence planning may result in the most cost effective path toreturn to the well plan 742, but may result in an almost immediate needfor a second correction due to a pending deviation within the well plan.Accordingly, a convergence path that merges the pending deviation withthe correction by selecting a convergence point beyond the pendingdeviation might be selected when considering total well costs.

It is understood that the diagram 740 of FIG. 7C is a two dimensionalrepresentation of a three dimensional environment. Accordingly, theillustrated convergence paths in the diagram 740 of FIG. 7C may be threedimensional. In addition, although the illustrated convergence paths allconverge with the planned path 742, is it understood that someconvergence paths may be calculated that move away from the planned path742 (although such paths may be rejected). Still other convergence pathsmay overshoot the actual path 742 and then converge (e.g., if thereisn't enough room to build the curve otherwise). Accordingly, manydifferent convergence path structures may be calculated.

Referring again to FIG. 7B, in step 736, the controller 144 producesrevised control parameters based on the convergence plan calculated instep 734. In step 738, the revised control parameters may be output. Itis understood that the revised control parameters may be provided to getthe drill bit back to the planned path 742 and the original controlparameters may then be used from that point on (starting at theconvergence point). For example, if the convergence plan selected thepath 748, the revised control parameters may be used until the bitreaches position 749. Once the bit reaches the position 749, theoriginal control parameters may be used for further drilling.Alternatively, the revised control parameters may incorporate theoriginal control parameters starting at the position 749 or mayre-calculate control parameters for the planned path even beyond thepoint 749. Accordingly, the convergence plan may result in controlparameters from the bit position 743 to the position 749, and furthercontrol parameters may be reused or calculated depending on theparticular implementation of the controller 144.

Referring to FIG. 8A, a method 800 illustrates a more detailedembodiment of step 734 of FIG. 7B. It is understood that the convergenceplan of step 734 may be calculated in many different ways, and that 800method provides one possible approach to such a calculation when thegoal is to find the lowest cost solution vector. In the present example,cost may include both the financial cost of a solution and thereliability cost of a solution. Other costs, such as time costs, mayalso be included. For purposes of example, the diagram 740 of FIG. 7C isused.

In step 802, multiple solution vectors are calculated from the currentposition 743 to the planned path 742. These solution vectors may includethe paths 744, 746, 748, and 750. Additional paths (not shown in FIG.7C) may also be calculated. The number of solution vectors that arecalculated may vary depending on various factors. For example, thedistance available to build a needed curve to get back to the plannedpath 742 may vary depending on the current bit location and orientationrelative to the planned path. A greater number of solution vectors maybe available when there is a greater distance in which to build a curvethan for a smaller distance since the smaller distance may require amuch more aggressive build rate that excludes lesser build rates thatmay be used for the greater distance. In other words, the earlier anerror is caught, the more possible solution vectors there will generallybe due to the greater distance over which the error can be corrected.While the number of solution vectors that are calculated in this stepmay vary, there may be hundreds or thousands of solution vectorscalculated in some embodiments.

In step 804, any solution vectors that fall outside of defined limitsare rejected, such as solution vectors that fall outside the lower limit753 and the upper limit 754. For example, the path 744 would be rejectedbecause the convergence point 745 falls outside of the lower limit 753.It is understood that the path 744 may be rejected for an engineeringreason (e.g., the path would require a dogleg of greater than allowedseverity) prior to cost considerations, or the engineering reason may beconsidered a cost.

In step 806, a cost is calculated for each remaining solution vector. Asillustrated in FIG. 7C, the costs may be represented as a cost matrix(that may or may not be weighted) with each solution vector havingcorresponding costs in the cost matrix. In step 808, a minimum of thesolution vectors may be taken to identify the lowest cost solutionvector. It is understood that the minimum cost is one way of selectingthe desired solution vector, and that other ways may be used.Accordingly, step 808 is concerned with selecting an optimal solutionvector based on a set of target parameters, which may include one ormore of a financial cost, a time cost, a reliability cost, and/or anyother factors, such as an engineering cost like dogleg severity, thatmay be used to narrow the set of solution vectors to the optimalsolution vector.

By weighting the costs, the cost matrix can be customized to handle manydifferent cost scenarios and desired results. For example, if time is ofprimary importance, a time cost may be weighted over financial andreliability costs to ensure that a solution vector that is faster willbe selected over other solution vectors that are substantially the samebut somewhat slower, even though the other solution vectors may be morebeneficial in terms of financial cost and reliability cost. In someembodiments, step 804 may be combined with step 808 and solution vectorsfalling outside of the limits may be given a cost that ensures they willnot be selected. In step 810, the solution vector corresponding to theminimum cost is selected.

Referring to FIG. 8B, a method 820 illustrates one embodiment of anevent-based process that may be executed by the controller 144 of FIG.2A. It is understood that an event may represent many differentscenarios in the surface steerable system 201. In the present example,in step 822, an event may occur that indicates that a prediction is notcorrect based on what has actually occurred. For example, a formationlayer is not where it is expected (e.g., too high or low), a selectedbit did not drill as expected, or a selected mud motor did not buildcurve as expected. The prediction error may be identified by comparingexpected results with actual results or by using other detectionmethods.

In step 824, a reason for the error may be determined as the surfacesteerable system 201 and its data may provide an environment in whichthe prediction error can be evaluated. For example, if a bit did notdrill as expected, the method 820 may examine many different factors,such as whether the rock formation was different than expected, whetherthe drilling parameters were correct, whether the drilling parameterswere correctly entered by the driller, whether another error and/orfailure occurred that caused the bit to drill poorly, and whether thebit simply failed to perform. By accessing and analyzing the availabledata, the reason for the failure may be determined.

In step 826, a solution may be determined for the error. For example, ifthe rock formation was different than expected, the database 128 may beupdated with the correct rock information and new drilling parametersmay be obtained for the drilling rig 110. Alternatively, the current bitmay be tripped and replaced with another bit more suitable for the rock.In step 828, the current drilling predictions (e.g., well plan, buildrate, slide estimates) may be updated based on the solution and thesolution may be stored in the database 128 for use in futurepredictions. Accordingly, the method 820 may result in benefits forfuture wells as well as improving current well predictions.

Referring to FIG. 8C, a method 830 illustrates one embodiment of anevent-based process that may be executed by the controller 144 of FIG.2A. The method 830 is directed to recalibration forecasting that may betriggered by an event, such as an event detected in step 610 of FIG. 6.It is understood that the recalibration described in this embodiment maynot be the same as calculating a convergence plan, although calculatinga convergence plan may be part of the recalibration. As an example of arecalibration triggering event, a shift in ROP and/or GAMMA readings mayindicate that a formation layer (e.g., the layer 170A of FIG. 1B) isactually twenty feet higher than planned. This will likely impact thewell plan, as build rate predictions and other drilling parameters mayneed to be changed. Accordingly, in step 832, this event is identified.

In step 834, a forecast may be made as to the impact of the event. Forexample, the surface steerable system 201 may determine whether theprojected build rate needed to land the curve can be met based on thetwenty foot difference. This determination may include examining thecurrent location of the bit, the projected path, and similarinformation.

In step 836, modifications may be made based on the forecast. Forexample, if the projected build rate can be met, then modifications maybe made to the drilling parameters to address the formation depthdifference, but the modifications may be relatively minor. However, ifthe projected build rate cannot be met, the surface steerable system 201may determine how to address the situation by, for example, planning abit trip to replace the current BHA with a BHA capable of making a newand more aggressive curve.

Such decisions may be automated or may require input or approval by thedrilling engineer 302, geologist 304, or other individuals. For example,depending on the distance to the kick off point, the surface steerablesystem 201 may first stop drilling and then send an alert to anauthorized individual, such as the drilling engineer 302 and/orgeologist 304. The drilling engineer 302 and geologist 304 may thenbecome involved in planning a solution or may approve of a solutionproposed by the surface steerable system 201. In some embodiments, thesurface steerable system 201 may automatically implement its calculatedsolution. Parameters may be set for such automatic implementationmeasures to ensure that drastic deviations from the original well plando not occur automatically while allowing the automatic implementationof more minor measures.

It is understood that such recalibration forecasts may be performedbased on many different factors and may be triggered by many differentevents. The forecasting portion of the process is directed toanticipating what changes may be needed due to the recalibration andcalculating how such changes may be implemented. Such forecastingprovides cost advantages because more options may be available when aproblem is detected earlier rather than later. Using the previousexample, the earlier the difference in the depth of the layer isidentified, the more likely it is that the build rate can be met withoutchanging the BHA.

Referring to FIG. 8D, a method 840 illustrates one embodiment of anevent-based process that may be executed by the controller 144 of FIG.2A. The method 840 is directed to self-tuning that may be performed bythe controller 144 based on factors such as ROP, total cost, andreliability. By self-tuning, the controller 144 may execute a learningprocess that enables it to optimize the drilling performance of thedrilling rig 110. Furthermore, the self-tuning process enables a balanceto be reached that provides reliability while also lowering costs.Reliability in drilling operations is often tied to vibration and theproblems that vibration can cause, such as stick-slip and whirling. Suchvibration issues can damage or destroy equipment and can also result ina very uneven surface in the borehole that can cause other problems suchas friction loading of future drilling operations as pipe/casing passesthrough that area of the borehole. Accordingly, it is desirable tominimize vibration while optimizing performance, since over-correctingfor vibration may result in slower drilling than necessary. It isunderstood that the present optimization may involve a change in anydrilling parameter and is not limited to a particular piece of equipmentor control system. In other words, parameters across the entire drillingrig 110 and BHA may be changed during the self-tuning process.Furthermore, the optimization process may be applied to production byoptimizing well smoothness and other factors affecting production. Forexample, by minimizing dogleg severity, production may be increased forthe lifetime of the well.

Accordingly, in step 842, one or more target parameters are identified.For example, the target parameter may be an MSE of 50 ksi or an ROP of100 ft/hr that the controller 144 is to establish and maintain. In step844, a plurality of control parameters are identified for use with thedrilling operation. The control parameters are selected to meet thetarget MSE of 50 ksi or ROP of 100 ft/hr. The drilling operation isstarted with the control parameters, which may be used until the targetMSE or ROP is reached. In step 846, feedback information is receivedfrom the drilling operation when the control parameters are being used,so the feedback represents the performance of the drilling operation ascontrolled by the control parameters. Historical information may also beused in step 846. In step 848, an operational baseline is establishedbased on the feedback information.

In step 850, at least one of the control parameters is changed to modifythe drilling operation, although the target MSE or ROP should bemaintained. For example, some or all of the control parameters may beassociated with a range of values and the value of one or more of thecontrol parameters may be changed. In step 852, more feedbackinformation is received, but this time the feedback reflects theperformance of the drilling operation with the changed controlparameter. In step 854, a performance impact of the change is determinedwith respect to the operational baseline. The performance impact mayoccur in various ways, such as a change in MSE or ROP and/or a change invibration. In step 856, a determination is made as to whether thecontrol parameters are optimized. If the control parameters are notoptimized, the method 840 returns to step 850. If the control parametersare optimized, the method 840 moves to step 858. In step 858, theoptimized control parameters are used for the current drilling operationwith the target MSE or ROP and stored (e.g., in the database 128) foruse in later drilling operations and operational analyses. This mayinclude linking formation information to the control parameters in theregional database 128.

Referring to FIG. 9, one embodiment of a system architecture 900 isillustrated that may be used for the on-site controller 144 of FIG. 1A.The system architecture 900 includes interfaces configured to interactwith external components and internal modules configured to processinformation. The interfaces may include an input driver 902, a remotesynchronization interface 904, and an output interface 918, which mayinclude at least one of a graphical user interface (GUI) 906 and anoutput driver 908. The internal modules may include a database query andupdate engine/diagnostic logger 910, a local database 912 (which may besimilar or identical to the database 410 of FIG. 4), a guidance controlloop (GCL) module 914, and an autonomous control loop (ACL) module 916.It is understood that the system architecture 900 is merely one exampleof a system architecture that may be used for the controller 144 and thefunctionality may be provided for the controller 144 using manydifferent architectures. Accordingly, the functionality described hereinwith respect to particular modules and architecture components may becombined, further separated, and organized in many different ways.

It is understood that the computer steerable system 144 may performcertain computations to prevent errors or inaccuracies from accumulatingand throwing off calculations. For example, as will be described later,the input driver 902 may receive Wellsite Information TransferSpecification (WITS) input representing absolute pressure, while thesurface steerable system 144 needs differential pressure and needs anaccurate zero point for the differential pressure. Generally, thedriller will zero out the differential pressure when the drillstring ispositioned with the bit off bottom and full pump flow is occurring.However, this may be a relatively sporadic event. Accordingly, thesurface steerable system 144 may recognize when the bit is off bottomand target flow rate has been achieved and zero out the differentialpressure.

Another computation may involve block height, which needs to becalibrated properly. For example, block height may oscillate over a widerange, including distances that may not even be possible for aparticular drilling rig. Accordingly, if the reported range is sixtyfeet to one hundred and fifty feet and there should only be one hundredfeet, the surface steerable system 144 may assign a zero value to thereported sixty feet and a one hundred foot value to the reported onehundred and fifty feet. Furthermore, during drilling, error graduallyaccumulates as the cable is shifted and other events occur. The surfacesteerable system 144 may compute its own block height to predict whenthe next connection occurs and other related events, and may also takeinto account any error that may be introduced by cable issues.

Referring specifically to FIG. 9, the input driver 902 provides outputto the GUI 906, the database query and update engine/diagnostic logger910, the GCL 914, and the ACL 916. The input driver 902 is configured toreceive input for the on-site controller 144. It is understood that theinput driver 902 may include the functionality needed to receive variousfile types, formats, and data streams. The input driver 902 may also beconfigured to convert formats if needed. Accordingly, the input driver902 may be configured to provide flexibility to the controller 144 byhandling incoming data without the need to change the internal modules.In some embodiments, for purposes of abstraction, the protocol of thedata stream can be arbitrary with an input event defined as a singlechange (e.g., a real time sensor change) of any of the given inputs.

The input driver 902 may receive various types of input, including rigsensor input (e.g., from the sensor system 214 of FIG. 2A), well plandata, and control data (e.g., engineering control parameters). Forexample, rig sensor input may include hole depth, bit depth, toolface,inclination, azimuth, true vertical depth, gamma count, standpipepressure, mud flow rate, rotary RPMs, bit speed, ROP, and WOB. The wellplan data may include information such as projected starting and endinglocations of various geologic layers at vertical depth points along thewell plan path, and a planned path of the borehole presented in a threedimensional space. The control data may be used to define maximumoperating parameters and other limitations to control drilling speed,limit the amount of deviation permitted from the planned path, definelevels of authority (e.g., can an on-site operator make a particulardecision or should it be made by an off-site engineer), and similarlimitations. The input driver 902 may also handle manual input, such asinput entered via a keyboard, a mouse, or a touch screen. In someembodiments, the input driver 902 may also handle wireless signal input,such as from a cell phone, a smart phone, a PDA, a tablet, a laptop, orany other device capable of wirelessly communicating with the controller144 through a network locally and/or offsite.

The database query and update engine/diagnostic logger 910 receivesinput from the input driver 902, the GCL 914, and ACL 916, and providesoutput to the local database 912 and GUI 906. The database query andupdate engine/diagnostic logger 910 is configured to manage thearchiving of data to the local database 912. The database query andupdate engine/diagnostic logger 910 may also manage some functionalrequirements of a remote synchronization server (RSS) via the remotesynchronization interface 904 for archiving data that will be uploadedand synchronized with a remote database, such as the database 128 ofFIG. 1A. The database query and update engine/diagnostic logger 910 mayalso be configured to serve as a diagnostic tool for evaluatingalgorithm behavior and performance against raw rig data and sensorfeedback data.

The local database 912 receives input from the database query and updateengine/diagnostic logger 910 and the remote synchronization interface904, and provides output to the GCL 914, the ACL 916, and the remotesynchronization interface 904. It is understood that the local database912 may be configured in many different ways. As described in previousembodiments, the local database 912 may store both current and historicinformation representing both the current drilling operation with whichthe controller 144 is engaged as well as regional information from thedatabase 128.

The GCL 914 receives input from the input driver 902 and the localdatabase 912, and provides output to the database query and updateengine/diagnostic logger 910, the GUI 906, and the ACL 916. Although notshown, in some embodiments, the GCL 906 may provide output to the outputdriver 908, which enables the GCL 914 to directly control third partysystems and/or interface with the drilling rig alone or with the ACL916. An embodiment of the GCL 914 is discussed below with respect toFIG. 11.

The ACL 916 receives input from the input driver 902, the local database912, and the GCL 914, and provides output to the database query andupdate engine/diagnostic logger 910 and output driver 908. An embodimentof the ACL 916 is discussed below with respect to FIG. 12.

The output interface 918 receives input from the input driver 902, theGCL 914, and the ACL 916. In the present example, the GUI 906 receivesinput from the input driver 902 and the GCL 914. The GUI 906 may displayoutput on a monitor or other visual indicator. The output driver 908receives input from the ACL 916 and is configured to provide aninterface between the controller 144 and external control systems, suchas the control systems 208, 210, and 212 of FIG. 2A.

It is understood that the system architecture 900 of FIG. 9 may beconfigured in many different ways. For example, various interfaces andmodules may be combined or further separated. Accordingly, the systemarchitecture 900 provides one example of how functionality may bestructured to provide the controller 144, but the controller 144 is notlimited to the illustrated structure of FIG. 9.

Referring to FIG. 10, one embodiment of the input driver 902 of thesystem architecture 900 of FIG. 9 is illustrated in greater detail. Inthe present example, the input driver 902 may be configured to receiveinput via different input interfaces, such as a serial input driver 1002and a Transmission Control Protocol (TCP) driver 1004. Both the serialinput driver 1002 and the TCP input driver 1004 may feed into a parser1006.

The parser 1006 in the present example may be configured in accordancewith a specification such as WITS and/or using a standard such asWellsite Information Transfer Standard Markup Language (WITSML). WITS isa specification for the transfer of drilling rig-related data and uses abinary file format. WITS may be replaced or supplemented in someembodiments by WITSML, which relies on eXtensible Markup Language (XML)for transferring such information. The parser 1006 may feed into thedatabase query and update engine/diagnostic logger 910, and also to theGCL 914 and GUI 906 as illustrated by the example parameters of block1010. The input driver 902 may also include a non-WITS input driver 1008that provides input to the ACL 916 as illustrated by block 1012.

Referring to FIG. 11, one embodiment of the GCL 914 of FIG. 9 isillustrated in greater detail. In the present example, the GCL 914 mayinclude various functional modules, including a build rate predictor1102, a geo modified well planner 1104, a borehole estimator 1106, aslide estimator 1108, an error vector calculator 1110, a geologicaldrift estimator 1112, a slide planner 1114, a convergence planner 1116,and a tactical solution planner 1118. In the following description ofthe GCL 914, the term external input refers to input received fromoutside the GCL 914 (e.g., from the input driver 902 of FIG. 9), whileinternal input refers to input received by a GCL module from another GCLmodule.

The build rate predictor 1102 receives external input representing BHAand geological information, receives internal input from the boreholeestimator 1106, and provides output to the geo modified well planner1104, slide estimator 1108, slide planner 1114, and convergence planner1116. The build rate predictor 1102 is configured to use the BHA andgeological information to predict the drilling build rates of currentand future sections of a well. For example, the build rate predictor1102 may determine how aggressively the curve will be built for a givenformation with given BHA and other equipment parameters.

The build rate predictor 1102 may use the orientation of the BHA to theformation to determine an angle of attack for formation transitions andbuild rates within a single layer of a formation. For example, if thereis a layer of rock with a layer of sand above it, there is a formationtransition from the sand layer to the rock layer. Approaching the rocklayer at a ninety degree angle may provide a good face and a clean drillentry, while approaching the rock layer at a forty-five degree angle maybuild a curve relatively quickly. An angle of approach that is nearparallel may cause the bit to skip off the upper surface of the rocklayer. Accordingly, the build rate predictor 1102 may calculate BHAorientation to account for formation transitions. Within a single layer,the build rate predictor 1102 may use BHA orientation to account forinternal layer characteristics (e.g., grain) to determine build ratesfor different parts of a layer.

The BHA information may include bit characteristics, mud motor bendsetting, stabilization and mud motor bit to bend distance. Thegeological information may include formation data such as compressivestrength, thicknesses, and depths for formations encountered in thespecific drilling location. Such information enables a calculation-basedprediction of the build rates and ROP that may be compared to bothreal-time results (e.g., obtained while drilling the well) and regionalhistorical results (e.g., from the database 128) to improve the accuracyof predictions as the drilling progresses. Future formation build ratepredictions may be used to plan convergence adjustments and confirm thattargets can be achieved with current variables in advance.

The geo modified well planner 1104 receives external input representinga well plan, internal input from the build rate predictor 1102 and thegeo drift estimator 1112, and provides output to the slide planner 1114and the error vector calculator 1110. The geo modified well planner 1104uses the input to determine whether there is a more optimal path thanthat provided by the external well plan while staying within theoriginal well plan error limits. More specifically, the geo modifiedwell planner 1104 takes geological information (e.g., drift) andcalculates whether another solution to the target may be more efficientin terms of cost and/or reliability. The outputs of the geo modifiedwell planner 1104 to the slide planner 1114 and the error vectorcalculator 1110 may be used to calculate an error vector based on thecurrent vector to the newly calculated path and to modify slidepredictions.

In some embodiments, the geo modified well planner 1104 (or anothermodule) may provide functionality needed to track a formation trend. Forexample, in horizontal wells, the geologist 304 may provide the surfacesteerable system 144 with a target inclination that the surfacesteerable system 144 is to attempt to hold. For example, the geologist304 may provide a target to the directional driller 306 of 90.5-91degrees of inclination for a section of the well. The geologist 304 mayenter this information into the surface steerable system 144 and thedirectional driller 306 may retrieve the information from the surfacesteerable system 144. The geo modified well planner 1104 may then treatthe target as a vector target, for example, either by processing theinformation provided by the geologist 304 to create the vector target orby using a vector target entered by the geologist 304. The geo modifiedwell planner 1104 may accomplish this while remaining within the errorlimits of the original well plan.

In some embodiments, the geo modified well planner 1104 may be anoptional module that is not used unless the well plan is to be modified.For example, if the well plan is marked in the surface steerable system201 as non-modifiable, the geo modified well planner 1104 may bebypassed altogether or the geo modified well planner 1104 may beconfigured to pass the well plan through without any changes.

The borehole estimator 1106 receives external inputs representing BHAinformation, measured depth information, survey information (e.g.,azimuth and inclination), and provides outputs to the build ratepredictor 1102, the error vector calculator 1110, and the convergenceplanner 1116. The borehole estimator 1106 is configured to provide areal time or near real time estimate of the actual borehole and drillbit position and trajectory angle. This estimate may use both straightline projections and projections that incorporate sliding. The boreholeestimator 1106 may be used to compensate for the fact that a sensor isusually physically located some distance behind the bit (e.g., fiftyfeet), which makes sensor readings lag the actual bit location by fiftyfeet. The borehole estimator 1106 may also be used to compensate for thefact that sensor measurements may not be continuous (e.g., a sensormeasurement may occur every one hundred feet).

The borehole estimator 1106 may use two techniques to accomplish this.First, the borehole estimator 1106 may provide the most accurateestimate from the surface to the last survey location based on thecollection of all survey measurements. Second, the borehole estimator1106 may take the slide estimate from the slide estimator 1108(described below) and extend this estimation from the last survey pointto the real time drill bit location. Using the combination of these twoestimates, the borehole estimator 1106 may provide the on-sitecontroller 144 with an estimate of the drill bit's location andtrajectory angle from which guidance and steering solutions can bederived. An additional metric that can be derived from the boreholeestimate is the effective build rate that is achieved throughout thedrilling process. For example, the borehole estimator 1106 may calculatethe current bit position and trajectory 743 in FIG. 7C.

The slide estimator 1108 receives external inputs representing measureddepth and differential pressure information, receives internal inputfrom the build rate predictor 1102, and provides output to the boreholeestimator 1106 and the geo modified well planner 1104. The slideestimator 1108, which may operate in real time or near real time, isconfigured to sample toolface orientation, differential pressure,measured depth (MD) incremental movement, MSE, and other sensor feedbackto quantify/estimate a deviation vector and progress while sliding.

Traditionally, deviation from the slide would be predicted by a humanoperator based on experience. The operator would, for example, use along slide cycle to assess what likely was accomplished during the lastslide. However, the results are generally not confirmed until the MWDsurvey sensor point passes the slide portion of the borehole, oftenresulting in a response lag defined by the distance of the sensor pointfrom the drill bit tip (e.g., approximately fifty feet). This lagintroduces inefficiencies in the slide cycles due to over/undercorrection of the actual path relative to the planned path.

With the slide estimator 1108, each toolface update is algorithmicallymerged with the average differential pressure of the period between theprevious and current toolfaces, as well as the MD change during thisperiod to predict the direction, angular deviation, and MD progressduring that period. As an example, the periodic rate may be between tenand sixty seconds per cycle depending on the tool face update rate ofthe MWD tool. With a more accurate estimation of the slideeffectiveness, the sliding efficiency can be improved. The output of theslide estimator 1108 is periodically provided to the borehole estimator1106 for accumulation of well deviation information, as well to the geomodified well planner 1104. Some or all of the output of the slideestimator 1108 may be output via a display such as the display 250 ofFIG. 2B.

The error vector calculator 1110 receives internal input from the geomodified well planner 1104 and the borehole estimator 1106. The errorvector calculator 1110 is configured to compare the planned well path tothe actual borehole path and drill bit position estimate. The errorvector calculator 1110 may provide the metrics used to determine theerror (e.g., how far off) the current drill bit position and trajectoryare from the plan. For example, the error vector calculator 1110 maycalculate the error between the current position 743 of FIG. 7C to theplanned path 742 and the desired bit position 741. The error vectorcalculator 1110 may also calculate a projected bit position/projectedpath representing the future result of a current error as describedpreviously with respect to FIG. 7B.

The geological drift estimator 1112 receives external input representinggeological information and provides outputs to the geo modified wellplanner 1104, slide planner 1114, and tactical solution planner 1118.During drilling, drift may occur as the particular characteristics ofthe formation affect the drilling direction. More specifically, theremay be a trajectory bias that is contributed by the formation as afunction of drilling rate and BHA. The geological drift estimator 1112is configured to provide a drift estimate as a vector. This vector canthen be used to calculate drift compensation parameters that can be usedto offset the drift in a control solution.

The slide planner 1114 receives internal input from the build ratepredictor 1102, the geo modified well planner 1104, the error vectorcalculator 1110, and the geological drift estimator 1112, and providesoutput to the convergence planner 1116 as well as an estimated time tothe next slide. The slide planner 1114 is configured to evaluate aslide/drill ahead cost equation and plan for sliding activity, which mayinclude factoring in BHA wear, expected build rates of current andexpected formations, and the well plan path. During drill ahead, theslide planner 1114 may attempt to forecast an estimated time of the nextslide to aid with planning. For example, if additional lubricants (e.g.,beads) are needed for the next slide and pumping the lubricants into thedrill string needs to begin thirty minutes before the slide, theestimated time of the next slide may be calculated and then used toschedule when to start pumping the lubricants.

Functionality for a loss circulation material (LCM) planner may beprovided as part of the slide planner 1114 or elsewhere (e.g., as astand-alone module or as part of another module described herein). TheLCM planner functionality may be configured to determine whetheradditives need to be pumped into the borehole based on indications suchas flow-in versus flow-back measurements. For example, if drillingthrough a porous rock formation, fluid being pumped into the boreholemay get lost in the rock formation. To address this issue, the LCMplanner may control pumping LCM into the borehole to clog up the holesin the porous rock surrounding the borehole to establish a moreclosed-loop control system for the fluid.

The slide planner 1114 may also look at the current position relative tothe next connection. A connection may happen every ninety to one hundredfeet (or some other distance or distance range based on the particularsof the drilling operation) and the slide planner 1114 may avoid planninga slide when close to a connection and/or when the slide would carrythrough the connection. For example, if the slide planner 1114 isplanning a fifty foot slide but only twenty feet remain until the nextconnection, the slide planner 1114 may calculate the slide startingafter the next connection and make any changes to the slide parametersthat may be needed to accommodate waiting to slide until after the nextconnection. This avoids inefficiencies that may be caused by startingthe slide, stopping for the connection, and then having to reorient thetoolface before finishing the slide. During slides, the slide planner1114 may provide some feedback as to the progress of achieving thedesired goal of the current slide.

In some embodiments, the slide planner 1114 may account for reactivetorque in the drillstring. More specifically, when rotating isoccurring, there is a reactional torque wind up in the drillstring. Whenthe rotating is stopped, the drillstring unwinds, which changes toolfaceorientation and other parameters. When rotating is started again, thedrillstring starts to wind back up. The slide planner 1114 may accountfor this reactional torque so that toolface references are maintainedrather than stopping rotation and then trying to adjust to an optimaltool face orientation. While not all MWD tools may provide toolfaceorientation when rotating, using one that does supply such informationfor the GCL 914 may significantly reduce the transition time fromrotating to sliding.

The convergence planner 1116 receives internal inputs from the buildrate predictor 1102, the borehole estimator 1106, and the slide planner1114, and provides output to the tactical solution planner 1118. Theconvergence planner 1116 is configured to provide a convergence planwhen the current drill bit position is not within a defined margin oferror of the planned well path. The convergence plan represents a pathfrom the current drill bit position to an achievable and optimalconvergence target point along the planned path. The convergence planmay take account the amount of sliding/drilling ahead that has beenplanned to take place by the slide planner 1114. The convergence planner1116 may also use BHA orientation information for angle of attackcalculations when determining convergence plans as described above withrespect to the build rate predictor 1102. The solution provided by theconvergence planner 1116 defines a new trajectory solution for thecurrent position of the drill bit. The solution may be real time, nearreal time, or future (e.g., planned for implementation at a futuretime). For example, the convergence planner 1116 may calculate aconvergence plan as described previously with respect to FIGS. 7C and 8.

The tactical solution planner 1118 receives internal inputs from thegeological drift estimator 1112 and the convergence planner 1116, andprovides external outputs representing information such as toolfaceorientation, differential pressure, and mud flow rate. The tacticalsolution planner 1118 is configured to take the trajectory solutionprovided by the convergence planner 1116 and translate the solution intocontrol parameters that can be used to control the drilling rig 110. Forexample, the tactical solution planner 1118 may take the solution andconvert the solution into settings for the control systems 208, 210, and212 to accomplish the actual drilling based on the solution. Thetactical solution planner 1118 may also perform performance optimizationas described previously. The performance optimization may apply tooptimizing the overall drilling operation as well as optimizing thedrilling itself (e.g., how to drill faster).

Other functionality may be provided by the GCL 914 in additional modulesor added to an existing module. For example, there is a relationshipbetween the rotational position of the drill pipe on the surface and theorientation of the downhole toolface. Accordingly, the GCL 914 mayreceive information corresponding to the rotational position of thedrill pipe on the surface. The GCL 914 may use this surface positionalinformation to calculate current and desired toolface orientations.These calculations may then be used to define control parameters foradjusting the top drive or Kelly drive to accomplish adjustments to thedownhole toolface in order to steer the well.

For purposes of example, an object-oriented software approach may beutilized to provide a class-based structure that may be used with theGCL 914 and/or other components of the controller 144. In the presentembodiment, a drilling model class is defined to capture and define thedrilling state throughout the drilling process. The class may includereal-time information. This class may be based on the followingcomponents and sub-models: a drill bit model, a borehole model, a rigsurface gear model, a mud pump model, a WOB/differential pressure model,a positional/rotary model, an MSE model, an active well plan, andcontrol limits. The class may produce a control output solution and maybe executed via a main processing loop that rotates through the variousmodules of the GCL 914.

The drill bit model may represent the current position and state of thedrill bit. This model includes a three dimensional position, a drill bittrajectory, BHA information, bit speed, and toolface (e.g., orientationinformation). The three dimensional position may be specified innorth-south (NS), east-west (EW), and true vertical depth (TVD). Thedrill bit trajectory may be specified as an inclination and an azimuthangle. The BHA information may be a set of dimensions defining theactive BHA. The borehole model may represent the current path and sizeof the active borehole. This model includes hole depth information, anarray of survey points collected along the borehole path, a gamma log,and borehole diameters. The hole depth information is for the currentdrilling job. The borehole diameters represent the diameters of theborehole as drilled over the current drill job.

The rig surface gear model may represent pipe length, block height, andother models, such as the mud pump model, WOB/differential pressuremodel, positional/rotary model, and MSE model. The mud pump modelrepresents mud pump equipment and includes flow rate, standpipepressure, and differential pressure. The WOB/differential pressure modelrepresents drawworks or other WOB/differential pressure controls andparameters, including WOB. The positional/rotary model represents topdrive or other positional/rotary controls and parameters includingrotary RPM and spindle position. The active well plan represents thetarget borehole path and may include an external well plan and amodified well plan. The control limits represent defined parameters thatmay be set as maximums and/or minimums. For example, control limits maybe set for the rotary RPM in the top drive model to limit the maximumRPMs to the defined level. The control output solution represents thecontrol parameters for the drilling rig 110.

The main processing loop can be handled in many different ways. Forexample, the main processing loop can run as a single thread in a fixedtime loop to handle rig sensor event changes and time propagation. If norig sensor updates occur between fixed time intervals, a time onlypropagation may occur. In other embodiments, the main processing loopmay be multi-threaded.

Each functional module of the GCL 914 may have its behavior encapsulatedwithin its own respective class definition. During its processingwindow, the individual units may have an exclusive portion in time toexecute and update the drilling model. For purposes of example, theprocessing order for the modules may be in the sequence of geo modifiedwell planner 1104, build rate predictor 1102, slide estimator 1108,borehole estimator 1106, error vector calculator 1110, slide planner1114, convergence planner 1116, geological drift estimator 1112, andtactical solution planner 1118. It is understood that other sequencesmay be used.

In the present embodiment, the GCL 914 may rely on a programmable timermodule that provides a timing mechanism to provide timer event signalsto drive the main processing loop. While the controller 144 may relypurely on timer and date calls driven by the programming environment(e.g., java), this would limit timing to be exclusively driven by systemtime. In situations where it may be advantageous to manipulate the clock(e.g., for evaluation and/or testing), the programmable timer module maybe used to alter the time. For example, the programmable timer modulemay enable a default time set to the system time and a time scale of1.0, may enable the system time of the controller 144 to be manuallyset, may enable the time scale relative to the system time to bemodified, and/or may enable periodic event time requests scaled to thetime scale to be requested.

Referring to FIG. 12, one embodiment of the ACL 916 provides differentfunctions to the controller 144. The ACL 916 may be considered a secondfeedback control loop that operates in conjunction with a first feedbackcontrol loop provided by the GCL 914. The ACL 916 may also provideactual instructions to the drilling rig 110, either directly to thedrilling equipment 216 or via the control systems 208, 210, and 212. TheACL 916 may include a positional/rotary control logic block 1202,WOB/differential pressure control logic block 1204, fluid circulationcontrol logic block 1206, and a pattern recognition/error detectionblock 1208.

One function of the ACL 916 is to establish and maintain a targetparameter (e.g., an ROP of a defined value of ft/hr) based on input fromthe GCL 914. This may be accomplished via control loops using thepositional/rotary control logic block 1202, WOB/differential pressurecontrol logic block 1204, and fluid circulation control logic block1206. The positional/rotary control logic block 1202 may receive sensorfeedback information from the input driver 902 and set point informationfrom the GCL 914 (e.g., from the tactical solution planner 1118). Thedifferential pressure control logic block 1204 may receive sensorfeedback information from the input driver 902 and set point informationfrom the GCL 914 (e.g., from the tactical solution planner 1118). Thefluid circulation control logic block 1206 may receive sensor feedbackinformation from the input driver 902 and set point information from theGCL 914 (e.g., from the tactical solution planner 1118).

The ACL 916 may use the sensor feedback information and the set pointsfrom the GCL 914 to attempt to maintain the established targetparameter. More specifically, the ACL 916 may have control over variousparameters via the positional/rotary control logic block 1202,WOB/differential pressure control logic block 1204, and fluidcirculation control logic block 1206, and may modulate the variousparameters to achieve the target parameter. The ACL 916 may alsomodulate the parameters in light of cost-driven and reliability-drivendrilling goals, which may include parameters such as a trajectory goal,a cost goal, and/or a performance goal. It is understood that theparameters may be limited (e.g., by control limits set by the drillingengineer 306) and the ACL 916 may vary the parameters to achieve thetarget parameter without exceeding the defined limits. If this is notpossible, the ACL 916 may notify the on-site controller 144 or otherwiseindicate that the target parameter is currently unachievable.

In some embodiments, the ACL 916 may continue to modify the parametersto identify an optimal set of parameters with which to achieve thetarget parameter for the particular combination of drilling equipmentand formation characteristics. In such embodiments, the controller 144may export the optimal set of parameters to the database 128 for use informulating drilling plans for other drilling projects.

Another function of the ACL 916 is error detection. Error detection isdirected to identifying problems in the current drilling process and maymonitor for sudden failures and gradual failures. In this capacity, thepattern recognition/error detection block 1208 receives input from theinput driver 902. The input may include the sensor feedback received bythe positional/rotary control logic block 1202, WOB/differentialpressure control logic block 1204, and fluid circulation control logicblock 1206. The pattern recognition/error detection block 1208 monitorsthe input information for indications that a failure has occurred or forsudden changes that are illogical.

For example, a failure may be indicated by an ROP shift, a radicalchange in build rate, or any other significant changes. As anillustration, assume the drilling is occurring with an expected ROP of100 ft/hr. If the ROP suddenly drops to 50 ft/hr with no change inparameters and remains there for some defined amount of time, anequipment failure, formation shift, or another event has occurred.Another error may be indicated when MWD sensor feedback has beensteadily indicating that drilling has been heading north for hours andthe sensor feedback suddenly indicates that drilling has reversed in afew feet and is heading south. This change clearly indicates that afailure has occurred. The changes may be defined and/or the patternrecognition/error detection block 1208 may be configured to watch fordeviations of a certain magnitude. The pattern recognition/errordetection block 1208 may also be configured to detect deviations thatoccur over a period of time in order to catch more gradual failures orsafety concerns.

When an error is identified based on a significant shift in inputvalues, the controller 114 may send an alert. This enables an individualto review the error and determine whether action needs to be taken. Forexample, if an error indicates that there is a significant loss of ROPand an intermittent change/rise in pressure, the individual maydetermine that mud motor chunking has likely occurred with rubbertearing off and plugging the bit. In this case, the BHA may be trippedand the damage repaired before more serious damage is done. Accordingly,the error detection may be used to identify potential issues that areoccurring before they become more serious and more costly to repair.

Another function of the ACL 916 is pattern recognition. Patternrecognition is directed to identifying safety concerns for rig workersand to provide warnings (e.g., if a large increase in pressure isidentified, personnel safety may be compromised) and also to identifyingproblems that are not necessarily related to the current drillingprocess, but may impact the drilling process if ignored. In thiscapacity, the pattern recognition/error detection block 1208 receivesinput from the input driver 902. The input may include the sensorfeedback received by the positional/rotary control logic block 1202,WOB/differential pressure control logic block 1204, and fluidcirculation control logic block 1206. The pattern recognition/errordetection block 1208 monitors the input information for specific definedconditions. A condition may be relatively common (e.g., may occurmultiple times in a single borehole) or may be relatively rare (e.g.,may occur once every two years). Differential pressure, standpipepressure, and any other desired conditions may be monitored. If acondition indicates a particular recognized pattern, the ACL 916 maydetermine how the condition is to be addressed. For example, if apressure spike is detected, the ACL 916 may determine that the drillingneeds to be stopped in a specific manner to enable a safe exit.Accordingly, while error detection may simply indicate that a problemhas occurred, pattern recognition is directed to identifying futureproblems and attempting to provide a solution to the problem before theproblem occurs or becomes more serious.

Referring to FIG. 13, one embodiment of a computer system 1300 isillustrated. The computer system 1300 is one possible example of asystem component or device such as the on-site controller 144 of FIG.1A. In scenarios where the computer system 1300 is on-site, such as atthe location of the drilling rig 110 of FIG. 1A, the computer system maybe contained in a relatively rugged, shock-resistant case that ishardened for industrial applications and harsh environments.

The computer system 1300 may include a central processing unit (“CPU”)1302, a memory unit 1304, an input/output (“I/O”) device 1306, and anetwork interface 1308. The components 1302, 1304, 1306, and 1308 areinterconnected by a transport system (e.g., a bus) 1310. A power supply(PS) 1312 may provide power to components of the computer system 1300,such as the CPU 1302 and memory unit 1304. It is understood that thecomputer system 1300 may be differently configured and that each of thelisted components may actually represent several different components.For example, the CPU 1302 may actually represent a multi-processor or adistributed processing system; the memory unit 1304 may includedifferent levels of cache memory, main memory, hard disks, and remotestorage locations; the I/O device 1306 may include monitors, keyboards,and the like; and the network interface 1308 may include one or morenetwork cards providing one or more wired and/or wireless connections toa network 1314. Therefore, a wide range of flexibility is anticipated inthe configuration of the computer system 1300.

The computer system 1300 may use any operating system (or multipleoperating systems), including various versions of operating systemsprovided by Microsoft (such as WINDOWS), Apple (such as Mac OS X), UNIX,and LINUX, and may include operating systems specifically developed forhandheld devices, personal computers, and servers depending on the useof the computer system 1300. The operating system, as well as otherinstructions (e.g., software instructions for performing thefunctionality described in previous embodiments) may be stored in thememory unit 1304 and executed by the processor 1302. For example, if thecomputer system 1300 is the controller 144, the memory unit 1304 mayinclude instructions for performing methods such as the methods 600 ofFIG. 6, 700 of FIG. 7A, 720 of FIG. 7B, 800 of FIG. 8A, 820 of FIG. 8B,830 of FIG. 8C, and 840 of FIG. 8D.

As described above, there are many challenges when drilling a well.Among other things, the location of the well borehole, including itslocation relative to lease boundaries or other items, may be veryimportant to know. In many situations, a number of wells may be drilledin close proximity to one another. In such situations, knowing thelocation of each borehole relative to each other borehole can be veryimportant too, such as to avoid a collision between boreholes and/or tomaximize production of hydrocarbons. As explained below, the use offiber optic cable in a borehole can be used to assist with locating aborehole more accurately.

Fiber optic distributed sensing in a well borehole may be used forcost-effective, continuous, real-time measurements along the entirelength of a fiber optic cable, an advantage over discrete sensors usedat pre-determined points. The optical fiber itself may be used as thesensing element, so no transducers need be used in the optical path.

Fiber optic cabling in a well borehole can be used for distributedsensing for locating relative positions of lateral wells, regardless ofthe length of the lateral well. With conventional MWD surveys, erroraccumulation often occurs due to the accumulation of sensor errors overthe length of the borehole. Positioning of lateral wells may requireaccuracy with high confidence in location, particularly as lateral wellsbecome longer. By drilling a first well and running fiber optic cablealong the length of the first borehole, the shape and position of asecond well relative to the first well can be accurately quantified. Therelative position of lateral wells can be important in order to maximizeproduction and avoid stranded hydrocarbons, and/or to avoid leaseboundary problems. The accuracy or resolution of the measurement withfiber optic cable may be in the range of five feet, one foot, or evenjust inches.

In one embodiment, illustrated in FIG. 14, a first well borehole 1400 isdrilled, and fiber optic cabling 1402 can be placed in the borehole ofwell 1400, such as directly outside the casing of the well 1400. Thefiber optic cabling 1402 can be used as a distributed sensor duringdrilling (or after drilling) of a subsequent well 1404.

In one embodiment, the casing for a first well borehole may include oneor more fiber optic cables. The fiber optic cabling 1402 in a wellborehole can provide a number of interesting and useful measurements,including use as a distributed sensor. In this particular embodiment,the casing in a first well 1400 may include a first fiber optic cabling1402. The fiber optic cabling 1402 may extend the entire length of theborehole 1400, a portion of the borehole 1400, or may extend forselected portions of the borehole 1400. The fiber optic cabling 1402 maybe used as a sensor, such as in connection with the drilling or locationof a second or more additional well boreholes. In pad drilling, forexample, a pad on the surface is typically used as a basis for drillinga number of wells. In pad drilling, and in many other situations, suchas steam assisted gravity drainage applications, the exact placement ofeach well borehole relative to each other well borehole can becomecritical. In addition, because of legal requirements, the exactplacement of a borehole's location may be critical to ensure that thewellbore does not extend beyond the authorized area (e.g., a leaseboundary) for the well. The present disclosure provides systems andmethods that may be useful in connection with pad drilling and drillingfor steam assisted gravity drainage, among other useful applications.

When a second well borehole 1404 is drilled in proximity to the firstborehole 1400, the fiber optic cabling 1402 can serve as a distributedsensor during drilling operations. For example, while the secondborehole 1404 is being drilled, the drilling operations create acousticvibrations which travel through the earth and the geological formationstherein. The fiber optic cabling 1402 can detect the acoustic signalsreceived along the length of the cabling 1402 (or one or more portionsthereof). The signals received by the cabling 1402 can be provided to acomputer system coupled to the fiber optic cabling 1402 (by wired orwireless connection), and can be recorded and stored in memory. Thesignals can be processed by one or more computer systems (not shown inFIG. 14) to determine the relative location and three-dimensional shapeof the second borehole 1404. In addition, the acoustic signals from thedrilling of the second borehole 1404 can be processed by one or morecomputer systems in real time while the second borehole 1404 is beingdrilled, the location of the second borehole 1404 can be determined, andthe location of the second borehole 1404 can be checked against one ormore threshold limits and/or a drill plan, such as to see if alterationsor corrections to the drilling plan or drilling operations areindicated. If so, one or more drilling parameters or operations may beautomatically adjusted or initiated to correctly drill the secondborehole 1404, such as described above. In addition, the location of thesecond borehole 1404 can be used to update a drill plan for the secondborehole, and the location can also be used to send one or more controlsignals to one or more drilling rig control systems to alter one or moredrilling rig parameters (e.g., rate of penetration, weight on bit,differential pressure, torque, RPMs, and the like), to determine if oneor more slide drilling operations is needed and, if so, the expectedduration and direction of the slide drilling, and/or to determinewhether the signals are normal (e.g., within threshold limits) orwhether the signals indicate an undesired event has happened or islikely to happen, such as, for example, if the signals' character or achange therein indicates that the drill bit has entered a particulargeological formation or type of formation. In one particular embodiment,the fiber optic cabling 1402 can be used as a distributed seismicsensor.

Although not shown, the cabling 1402 may be coupled to a surfacesteerable system like that described above. In addition, oralternatively, the cabling 1402 may be coupled to one or more drillingrig control systems (not shown). These connections may be wired orwireless, and may be in addition to the computer system mentioned abovefor receiving and processing the data received from the fiber opticcabling 1402 and its sensing of acoustic signals from the drilling of asecond well borehole. The data from the cabling 1402, for example, maybe provided to the surface steerable system for processing or may beprovided to a surface steerable system in addition to a computer systemfor processing the data. In such situations, the surface steerablesystem may use the data from the cabling 1402 for one or moredeterminations, such as whether the second well borehole is inaccordance with a well plan therefor, whether a slide drilling operationis indicated and the length, direction, and likely duration of theslide, whether the data is consistent or inconsistent with expectations(such as determined by comparison with historical data from the firstwell, an earlier-drilled portion of the second well, and/or anotherwell) with respect to the geological formations, and so forth.

Although not shown in FIG. 14, additional fiber optic cabling canoptionally be inserted in a second or subsequent wells to provideadditional data and greater resolution for lateral well spacing, such asin multi-well pads, for subsequently-drilled wells. When fiber opticcabling 1402 is located in two or more boreholes, and a third orsubsequent well borehole is drilled, the cabling 1402 in the earlier twoor more well boreholes can be used to triangulate the acoustic signalsreceived from the third or later well borehole when it is drilled, thusproviding even greater accuracy or resolution of the location and 3Dshape of the third or later well borehole when such signals areprocessed. As drilling occurs in new wells, the fiber cabling 1402 inthe original well can be used to sense acoustic signals 1406 whichprovide information about each borehole's distance from the first well.As subsequent wells are drilled, the fiber optic cabling 1402 sensesacoustic signals from the drilling and then provides information thatmaps exactly how far away the wells are spaced from each other and the3D geometry of the wells. In this way, drillers can achieve an idealspacing between wells, as well as greater confidence in the shape andlocation of each well borehole.

In one embodiment, the computer system used to process the data from thecabling 1402 can be coupled to a 2D or 3D display that shows thelocation and/or shape of second well borehole 1404 and also the locationof the second well borehole 1404 relative to the location of the firstwell borehole 1400. This display can be updated in real time as thesecond well borehole 1404 is being drilled. In addition, the computersystem can be programmed to process additional data from the cabling1402 as it is received and automatically recalculate the location and/orshape of the second borehole 1404, then update the displayautomatically. In addition, the computer system can be programmed todisplay multiple well boreholes, including a third or subsequent wellborehole as it is being drilled, relative to the previously drilledboreholes. The display may include the dimensions of one or more of theborehole diameters and/or the distances between one or more of theboreholes, such as at one or more specific locations along the length ofthe borehole, or such as at the closest point between the boreholes.

In addition to or separately from a visual display of the locationand/or shape of a second or additional well boreholes, the computersystem can also be programmed to receive and store the audio signalsreceived from the fiber optic cabling in one or more well boreholes. Theaudio signals can be stored, indexed and tagged as audio files that areindexed with well and/or equipment information, for example, so that aparticular audio file may be stored with information indicating the wellthe file is from, the well borehole being drilled that is recorded bythe audio file, the drilling operations that were occurring thatcorrespond to the audio file (e.g., slide versus rotary drilling mode,RPM, ROP, WOB, differential pressure, formation being drilled, surfacetorque, etc.), and/or the drilling equipment used during the drillingthat corresponds to the audio file (e.g., drilling rig, drill bit, BHA,mud motor, etc.).

A computer database of such audio files and related informationcorresponding to one or more such files can be created and accessed by acomputer system. With such a database, the audio signals received fromthe fiber optic cabling while drilling a given well can be compared tostored audio files (either in real time during drilling or on anas-desired basis in response to an operator command). The computersystem can be programmed so that the audio signals from the fiber opticcable are compared to audio signals from earlier during drilling of thesame well or from a different well that was being drilled under the sameor similar conditions, such as slide drilling, use of a similar bit,drilling through the same formation, similar ROP, WOB, torque,differential pressure, etc. Thresholds can be used to automaticallyindicate when the audio signal from the fiber optic cable differssignificantly from the audio signals expected, such as indicated by oneor more stored audio files. When one or more audio signals from a wellbeing drilled exceed one or more threshold values (e.g., thresholds infrequency, amplitude, wavelength, variations thereof, or otherparameters), the computer system may be programmed to send one or morealerts, which may be visual, by email, text, or otherwise, and thecomputer system may be programmed to take one or more corrective actionsautomatically, such as by sending one or more control signals to one ormore rig control systems to alter one or more drilling parameters.

FIG. 15 illustrates one embodiment of a first well 1500. The first well1500 has a cased borehole 1400 with a computer system for seismic ordata analytics 1502 on the surface at the wellhead for receiving thedata from the fiber optic cabling 1402 as subsequent wells are drilled.

The computer system 1502 could be located remote from the well 1400. Forexample, the data received by the fiber optic cabling 1402 could betransmitted to a remote, second location from the well 1400, at whichthe system 1502 is located.

FIGS. 16A and 16B illustrate the potential placement of fiber opticcabling relative to the casing in a well. FIG. 16A depicts the casing1604 in well 1600A. The fiber optic cabling 1602 is located inside thecasing 1604 and within the tubing 1606. FIG. 16B shows placement offiber optic cabling outside the casing. FIG. 16B depicts the casing inwell 1600B. In 1600B, the fiber optic cabling 1602 is placed outside thecasing and tube. Further, a clamp or similar protective structure 1608which may be made of steel or cast iron, for example, holds the fiber inplace. A rigid centralizer (not shown) may also be used to affix thefiber optic cabling. The placement of the fiber optic cabling outsidethe casing (as illustrated in 16B) is considered more practical over thelong-term because it does not take up space within the casing tube.

In addition to providing information about the placement of lateralwells during drilling, the fiber optic distributed sensing cable 1402can provide a sonic measurement of parameters such as the porosity anddensity of the rock between two points. The cabling 1402 thuseffectively can be used as a logging tool for sonic evaluation ofgeological formations. The system can be modified by providing amodulated digitally-controlled signal source sending signals to thecabling 1402 within the original well to use a reference for calculatingthe distance to a subsequent well. Alternatively, the sound of rockbeing scraped by the bit or bottom hole assembly could provide thisinformation. As noted above, the cabling 1402 may provide the dataresulting from the sensed acoustic signals to a computer system forprocessing, which may include or may be in addition to a surfacesteerable system like that described above. Either system may use thedata received from the cabling 1402, compare it against historical data(such as from an earlier-drilled well, an earlier-drilled portion of thesecond well being drilled, and/or historical data from one or more otherwells), and, responsive to the comparison, determine the geologicalformation being drilled.

Besides the location, spacing, and shape of a second borehole andgeological changes encountered during drilling, the acoustic signalsreceived from the fiber optic cable 1402 can be used to identify otherevents or conditions during drilling of the second borehole 1404. Forexample, the signals received from the fiber optic cable can beprocessed by frequency domain and time domain signal processing, and theresults can be used to indicate conditions and events like bit wear,motor damage, and stick slip. The drill bit RPM can be determined fromthe processing of such signals, as well as mud motor lobe activity, andthe results of such information can be used to determine events orconditions such as leakage or stator chunking. It is believed that theprocessed signals can be used to confirm the functionality of equipmentsuch as agitators and establish the depth in the borehole at which thesurface oscillation of the drill pipe causes friction reducing motion ofthe drill string in the second borehole. Once this information isdetermined, then the system can dynamically adjust the surfaceoscillation of the drill pipe to optimize friction reduction withoutrotary motion of the drill string which might cause the toolfaceorientation to change. Thus, the signals from the fiber optic cabling1402 can be use identify and determine drilling conditions and events,as well as drilling parameters, and this information can be used by acomputer system programmed to automatically adjust the drillingoperations or one or more drilling parameters once a certain conditionor event has been identified.

The acoustic signals received from the fiber optic cable in one or morewells may be combined or processed by a computer system together withMWD information, as well as information received from downhole and/orsurface sensors. In addition to the use of a fiber optic cable in afirst well to assist with the determination of the location and/or shapeof a second or subsequent well, it is also believed that the fiber opticcable in a given well may be used to receive and provide acousticsignals that can be processed by a computer system and used (alone ortogether with additional information) to confirm the location and/orshape of that same well or to better refine the accuracy or precision ofthe location and/or shape of that same well.

Referring now to FIG. 17, a flow diagram illustrates a method 1700 ofplacing a fiber optic cable in a first well and using the fiber opticcable to locate a second well and drill the second well accordingly. Atstep 1705, a first well is drilled. In step 1710, one or more fiberoptic cables are located in the casing of the first well when the casingfor the first well is run. During step 1715, a second well is drilled.During the drilling of the second well, at step 1720, acoustic signalsfrom the drilling of the second well are received by the fiber opticcable in the first well. The fiber optic cable may act as a distributedsensor of such acoustic signals. The acoustic signals are thentransmitted by the fiber optic cable to a computer system for processingat step 1720. The computer system may process the signals to identifythe amplitude and frequency of the acoustic signals receive, and therebydetermine the relative location of the point of origination of theacoustic signals. An example of such method is provided in U.S.Published patent application Ser. No. 13/307,765, which was filed onNov. 30, 2011, and is entitled “Fiber Optic Cable for DistributedAcoustic Sensing with Increase Acoustic Sensitivity,” which is herebyincorporated by reference herein.

By analyzing the signals received from the fiber optic cable at step1720, the computer system can determine the location of the originationof the source of the acoustic signals; i.e., the drill bit that isdrilling the second well. By monitoring the location of the drill bitthrough the use of the fiber optic cable in the first well during thedrilling of all or portions of the second well, the location of thesecond wellbore can be determined. Moreover, the location of the secondwellbore as determined through the use of the fiber optic cable can becompared and used together with MWD information and/or otherinformation, such as geological information, to better and moreaccurately determine the location of the second wellbore, as well as itsshape.

At step 1730 in FIG. 17, the computer system may determine if thedrilling of the second well should be modified. For example, it may bethat the location of the second wellbore is not as desired or is notaccording to the well plan, or it may be according to the well plan, butnew information (e.g., regarding the geological formations drilled orabout to be drilled) may indicate that the drilling should deviate fromthe well plan. If it is determined that the drilling of the second wellis going to plan or is otherwise acceptable, then the computer systemmay simply continue the step of monitoring the drilling of the secondwell by returning to step 1715 and repeating the steps of receiving andanalyzing the acoustic data generated by the drilling of the second welland determining the location of the second wellbore and determiningwhether the location is acceptable or if drilling of the second wellshould be modified.

If a determination is made at step 1730 responsive to the location ofthe second wellbore that the location is potentially problematic suchthat the drilling of the second well should be modified, then thecomputer system at step 1735 may modify the drilling of the second well.The modification of the drilling of the second well may be accomplishedby sending one or more signals to a surface steerable system, which inturn may determine which drilling parameters or operations should bemodified. Alternatively, the computer system at step 1735 may send oneor more control signals to one or more control systems of the drillingrig that is drilling the second wellbore. The drilling operations forthe second wellbore may be modified by modifying one or more drillingparameters, such as those described above, including rate ofpenetration, weight on bit, torque, mud flow rate, etc. In addition, thecomputer system may be programmed to indicate that one or more drillingoperations are appropriate, such as a slide to alter the direction ofthe borehole. Moreover, the computer system at step 1735 may determinethat the well plan should be updated to reflect changes to the well planin light of the location of the second well borehole, and further may beprogrammed to then drill in accordance with the updated well plan. Itshould be noted that the computer system may be programmed to performany or all of the steps described and shown in FIG. 17 automatically, ormay be programmed to provide data to an operator (such as by a displayscreen or alert) and await instructions from the operator beforemodifying any drilling parameters or operations.

In yet another embodiment, the drilling of the second well my beperformed with systems and methods which selectively generate acousticsignals of particular amplitudes and/or frequencies. Using such systemsand methods can provide more distinct and clearer acoustic signals forthe fiber optic cable to receive. Such systems and methods can includethose shown and described in more detail in U.S. Pat. No. 9,057,258,which issued on Jun. 16, 2015, and is entitled “System and Method forUsing Controlled Vibrations for Borehole Communications,” and in U.S.Pat. No. 8,967,244, which issued on Mar. 3, 2015, and is entitled“System and Method for Steering in a Downhole Environment UsingVibration Modulation.” U.S. Pat. Nos. 9,057,258 and 8,967,244 are herebyincorporated by reference as if fully set forth herein.

It will be appreciated by those skilled in the art having the benefit ofthis disclosure that this system and method for surface steerabledrilling provides a way to plan a drilling process and to correct thedrilling process when either the process deviates from the plan or theplan is modified. It should be understood that the drawings and detaileddescription herein are to be regarded in an illustrative rather than arestrictive manner, and are not intended to be limiting to theparticular forms and examples disclosed. On the contrary, included areany further modifications, changes, rearrangements, substitutions,alternatives, design choices, and embodiments apparent to those ofordinary skill in the art, without departing from the spirit and scopehereof, as defined by the following claims. Thus, it is intended thatthe following claims be interpreted to embrace all such furthermodifications, changes, rearrangements, substitutions, alternatives,design choices, and embodiments.

What is claimed is:
 1. A system for determining the relative locationsof a plurality of well boreholes, the system comprising: a processor; amemory coupled to the processor, wherein the memory comprisesinstructions executable by the processor; and a fiber optic cablelocated in a first well borehole and coupled to the processor, whereinthe fiber optic cable is adapted to sense acoustic signals from drillingoperations for a second well borehole, and wherein the instructionscomprise instructions for receiving data from the fiber optic cablecorresponding to the acoustic signals, processing the data, anddetermining the location of the second well borehole relative to thelocation of the first well borehole.
 2. The system of claim 1 wherein atleast a portion of the fiber optic cable is located in a casing of thefirst well borehole.
 3. The system of claim 1 wherein the fiber opticcable is adapted to operate as a distributed sensor of acoustic signals.4. The system of claim 1 wherein the instructions further compriseinstructions for determining the shape of the second well borehole. 5.The system of claim 1 wherein the system's resolution of the location ofthe second well borehole relative to the location of the first wellborehole is less than one foot.
 6. The system of claim 1 wherein thesystem further comprises: a second fiber optic cable in a third wellborehole and coupled to the processor, wherein the second fiber opticcable is adapted to sense acoustic signals from drilling operations forthe second well borehole, and wherein the instructions further compriseinstructions for receiving data from the second fiber optic cablecorresponding to the acoustic signals, processing the data from both thefiber optic cable and the second fiber optic cable, triangulating thelocation of the second well borehole responsive to the acoustic signals,and determining the location of the second borehole relative to thelocation of the first well borehole and the third well borehole.
 7. Thesystem of claim 1 wherein at least a portion of the fiber optic cable islocated in a casing of the first well borehole, the fiber optic cable isadapted to operate as a distributed sensor of acoustic signals, andwherein the instructions further comprise instructions for takingcorrective action responsive to the determination of the location of thesecond borehole.
 8. A method of locating a relative position of a wellborehole, the method comprising: providing a computer system coupled toa fiber optic cable located in casing in a first well borehole, duringdrilling of a second well borehole, sensing, by the fiber optic cable,acoustic signals from the drilling of the second well borehole;providing data corresponding to the acoustic signals to the computersystem; and processing the data, by the computer system, to determinethe location of the second well borehole.
 9. The method of claim 8wherein the computer system is at a location remote from the first welland the second well.
 10. The method of claim 8 wherein the computersystem is adapted to monitor the data for compliance with a threshold.11. The method of claim 10, wherein the computer system is adapted todetermine if the threshold has been exceeded and to generate an alertemail, text message, display, audio alarm, or visual warning, and/or totake corrective action by sending a control signal to a control systemof a drilling rig drilling the second well borehole.
 12. The method ofclaim 8 wherein the location of the second well borehole relative to thefirst well borehole determined by the computer system has a resolutionof less than one foot.
 13. The method of claim 8 further comprising thesteps of: providing a second fiber optic cable in a third well borehole,wherein the second fiber optic cable is coupled to the computer system;providing second data responsive to acoustic signals from drillingoperations for the second well borehole that are sensed by the secondfiber optic cable to the computer system; processing the second data andthe data by the computer system; triangulating the location of thesecond well borehole responsive to the acoustic signals; and determiningthe location of the second well borehole relative to the location of thefirst well borehole and the third well borehole.
 14. The method of claim8 further comprising the step of updating a well plan for the secondwell responsive to the determination of the location of the second wellborehole.
 15. The method of claim 14 further comprising the step ofsending one or more signals to a control system for a drilling rig todrill the second well in accordance with the updated well plan.
 16. Asystem for determining information associated with a well, the systemcomprising: a processor; a memory coupled to the processor, the memorycomprising instructions executable by the processor; and a fiber opticcable located in a first well borehole and coupled to the processor,wherein the fiber optic cable is adapted to sense acoustic signals, andwherein the instructions comprise instructions for receiving signalsfrom the fiber optic cable responsive to acoustic signals received bythe fiber optic cable during drilling of a second well borehole,processing the signals received from the fiber optic cable, determiningone or more of the following: the location of the second well borehole,the shape of the second well borehole, the relative location of thesecond well borehole to the first well borehole, one or more geologicalformations being drilled, an event or condition of interest duringdrilling, and taking one or more corrective actions responsive to theevent or condition by sending one or more control signals to one or morecontrol systems of a drilling rig or a bottom hole assembly or otherequipment that is being used to drill the second well borehole.
 17. Thesystem of claim 16 wherein the fiber optic cable is adapted to operateas a distributed sensor of acoustic signals.
 18. The system of claim 16wherein at least a portion of the fiber optic cable is located in acasing of the first well borehole.
 19. The system of claim 16 whereinthe system's resolution of the location of the second well boreholerelative to the location of the first well borehole is less than onefoot.
 20. The system of claim 16 further comprising instructions forupdating a well plan for the second well responsive to the determinationof the location of the second well borehole.
 21. The system of claim 20further comprising instructions for sending one or more signals to acontrol system for a drilling rig to drill the second well in accordancewith the updated well plan.